A slow start to summer heat, compounded by plump injections throughout the shoulder season, kept a lid on June natural gas bidweek prices. Less-than-inspiring forecasts accompanied a mix of mostly small month/month adjustments throughout the Gulf Coast, Midwest and East; the NGI June Bidweek National Avg. crept 4.0 cents higher to $2.105/MMBtu.

The comparison to last year’s prices -- when the June 2018 bidweek National Avg. finished a hair under $2.50 -- helps show the discrepancy between mild May 2019 temperatures and the consistently warmer-than-normal conditions recorded in May 2018.

Last Wednesday, the Nymex June futures contract rode a 5.1-cent rally to roll off the board at $2.633. But since taking over as the prompt month, the July contract has moved decidedly in the other direction, plummeting a combined 17.0 cents Thursday and Friday to reach lows not seen since 2016. On Monday, the bears picked up where they left off, with the front month trading as low as $2.382 on the way to settling at $2.403.

The June expiry resulted in a 7.0-cent month/month increase for bidweek Henry Hub prices, which averaged $2.635. Most locations across the eastern two thirds of the Lower 48 moved in sympathy with the Louisiana benchmark, though gains at many locations in Louisiana, Texas and the Midwest lagged the hub.

Gains were slightly stronger in the Southeast, which has been the focal point of hot temperatures at this early stage of the cooling season. Transco Zone 4 added 8.0 cents to average $2.580 in June bidweek.

Record-level heat boosted cooling degree days in the Southeast to close out May, but not enough to drive consistently higher prices in the spot market. Meanwhile, forecasts have pointed to a mixed outlook on June temperatures across the Lower 48.

Coming out of the weekend, the latest guidance failed to deliver any hotter trends for the outlook through mid-June, according to NatGasWeather. The pattern from both American and European guidance heading into Monday’s trading was “not nearly hot enough” to rally the markets.

“We see potential for stronger heat building around June 18, although that’s far out and would need a greater amount of weather data to come on board for the markets to expect bearish weather headwinds to finally end,” the forecaster said. “There’s still expected to be bouts of hot conditions across the southern U.S.,” but “where there’s not much demand is across the northern half of the country” as temperatures there “will be quite comfortable during the first half of June, with highs mostly in the 70s and 80s.”

The lack of June heat presents a problem for bulls, who have been feeling the pressure from year/year production growth that has helped refill inventories at an above-average clip throughout the injection season. With bears tightening their grip, futures prices have been on a sharp downward trajectory for the summer contracts. July settled at $2.454 last Friday, and prices finished below $2.500 across the July-October strip.

“Our model indicates that last Friday’s final settlement price for the July-October natural gas contract strip is justified by the current oversupply condition in the U.S. market,” EBW Analytics Group CEO Andy Weissman said. “...For most of 2018, the natural gas supplies flowing into the United States far exceeded market needs in normal weather. This structural oversupply, however, was masked by far higher-than-normal weather from early April through the first week of December.

“This extended period of much greater-than-normal weather-driven demand finally ended during the first two months of the injection season in 2019, erasing almost entirely the storage deficits that persisted for much of the past year and pushing prices down sharply.”

This comes as forecasts for June have advertised neutral conditions, offering “few signs of significant hotter-than-normal weather except in the western U.S. and portions of the Southeast,” he added. “The natural gas market frequently puts disproportionate weight on start-of-season weather. Until forecasts start to call for hotter weather, prices are likely to remain weak.”

Last week the Energy Information Administration (EIA) reported a much larger-than-expected 114 Bcf injection into U.S. natural gas stocks for the week ended May 24, versus a 95 Bcf build recorded in the year-ago period and the five-year average 97 Bcf injection. Total Lower 48 working gas in underground storage stood at 1,867 Bcf as of May 24, 156 Bcf (9.1%) higher than year-ago levels but 257 Bcf (minus 12.1%) below the five-year average, according to EIA.

This injection implied the market was 5.3 Bcf/d looser than last year adjusting for weather, and the market had averaged 2.7 Bcf/d looser over the previous four weeks, according to analysts with Raymond James & Associates.

Genscape Inc. viewed the figure as about 6.0 Bcf/d loose versus the five-year average when compared to degree days and normal seasonality.

Analysts with Jefferies LLC observed that injections have continued to run above average but were only around 18% above average in May compared to around 141% larger than average in April.

In terms of balances, May production was averaging 87.1 Bcf/d as of late last week, “just ahead of April’s record production of 86.9 Bcf/d,” according to the Jefferies team. “Production is up 7.0 Bcf/d year/year, the lowest year/year growth since November 2017. Haynesville production has continued its climb, averaging a new high of 11.4 Bcf/d thus far in May.

West Texas Woes Continue

As traders were having to circumnavigate a restriction on northbound flows via the Natural Gas Pipeline Co. of America (NGPL) during bidweek, June prices tumbled throughout West Texas, with most locations in the region posting a negative average. Waha averaged minus 25.0 cents after shedding 34.0 cents month/month. Further north, NGPL Midcontinent also showed signs of impact from the maintenance-related constraints, with bidweek prices shedding 22.5 cents to average $1.680.

As evidenced by June bidweek trading, the glut of associated gas output and limited takeaway capacity continues to hammer Permian Basin prices. But the outlook offers hope that conditions could improve for Permian producers in the not-too-distant future.

One potential uplift for Permian prices could come from the start-up of new pipeline capacity south of the border with Mexico, according to RBN Energy LLC analyst Jason Ferguson.

“Gas exports to Mexico from West Texas have been thwarted by construction delays for new pipeline capacity on the Mexico side,” Ferguson said. “Well, that may be changing. It appears that the buildout of gas pipelines in Northwest Mexico has progressed recently, as exports from Waha to the U.S.-Mexico border recently topped 0.5 Bcf/d...The gains appear to be tied to the impending completion of Fermaca’s pipeline network within Mexico.

“...Once the Fermaca pipelines to Central Mexico are completed, increases in exports from Waha are likely, although there appears to be a wide range of export expectations in the market. For our part, we see Waha’s exports to Mexico building gradually once the Fermaca pipelines are in place.”

Depending on the timeline for completing the Fermaca pipelines, exports from Waha to Mexico could climb to more than 600 MMcf/d this month, potentially reaching more than 800 MMcf/d by the fourth quarter, according to Ferguson.

Meanwhile, whispers that Kinder Morgan Inc.’s Gulf Coast Express (GCX) project could enter service ahead of schedule hint at another possible boost for Permian prices, the analyst said.

“While the official start date for GCX is October of this year, market buzz continues to indicate the potential for some type of interim service before then,” Ferguson said. “While we have no way of knowing if this is the case, we have at least been able to verify that it’s technically feasible to move some volumes on the pipeline before all of the compression has been completed.

“This is possible because the pipeline will be receiving gas at high pressures from Permian processing plants, thereby facilitating flows from West Texas to the Agua Dulce Hub even without the additional compression. While the amounts that could be achieved from such a setup would vary based on the pressure at the different processing plant receipt meters, we’ve heard that amounts near 0.5 Bcf/d would be technically feasible if gas is received at around 1,000 pounds per square inch gauge (psig) at the plant and delivered at 800 psig at Agua Dulce.”

Elsewhere in June bidweek trading, Northeast prices were mixed, with locations throughout the region trading at a discount to Henry Hub. Algonquin Citygate dropped 4.5 cents to average $2.330.

The 680 MW Pilgrim Nuclear Power Station in Plymouth, MA, officially retired as of June 1, which could open up opportunities, both long- and short-term, for natural gas-fired power generation, according to Genscape analyst Joe Bernardi.

“This plant has provided baseload generation to the ISO New England stack, which proved crucial as ISO New England’s gas generation is supply constrained,” Bernardi said.

A one-to-one replacement of Pilgrim’s generation load would amount to roughly 95 MMcf/d of additional gas demand, according to the analyst.

“Bridgeport Harbor’s 488.5 MW expansion was also required to be fully operational by June 1,” Bernardi said. “Iroquois’ Stratford meter already feeds the other Bridgeport Harbor units, and it has seen a recent uptick in demand to reach a new max of around 120 MMcf/d. Alternative supply may also be brought on from Tennessee Gas Pipeline.

“Additionally, the quick start 333 MW gas-burning Canal Unit 3 recently cleared the power forward capacity market, and its capacity supply obligation began on June 1, but it will likely run as a peaker during times of high power prices. Canal and Bridgeport can help fill the gap left by Pilgrim’s retirement. However, come winter, the loss of Pilgrim will bring further volatility” to New England as the region “sees an increasing reliance on gas.”

Trade Threats Foster Macro Uncertainty

Meanwhile, as if natural gas bears needed any help making their case heading into the summer, the broader economy uncertainty created by U.S. trade hostilities has cast a shadow over energy commodities.

The ongoing escalation of tariffs between the United States and China has already ensnared U.S. liquefied natural gas exports, but the Trump Administration’s unexpected announcement of new tariffs on Mexico late last week seemed to renew anxieties among investors.

“The market took another hit on Friday, and the culprit was yet again trade-related -- but this time it had nothing to do with China,” analysts with Raymond James & Associates said in a note to clients Monday. “After the White House abruptly announced a 5% tariff on Mexican imports -- with the potential for further escalation -- heightened fears of economic damage sent the S&P 500 down 1.3%.

“Commodity prices fared even worse, as the macro fears coupled with” a bearish crude oil inventory report from the Department of Energy last week pushed West Texas Intermediate and Brent prices “down 5.8% and 5.6% to $53.30/bbl and $61.68/bbl, respectively,” the analysts said. “Oil’s poor showing on Friday made May the worst month for crude since last November’s sell-off.”

The prospect of continued tariffs targeting U.S. trading partners presents downside demand risks for natural gas, which would be bad timing given the oversupply in the market, according to Powerhouse CEO Alan Levine.

“I think what’s happening is the uncertainties we’re facing because of the guidance we’re receiving out of Washington, which has us concerned that demand is going to fall” amid continued sparring over trade, Levine told NGI. “...We’re starting to develop export markets for natural gas. I think there’s a lot of anxiety now as to what might be available there.

“Remember, we’re not the only ones that can interfere with the normal flow of business. So we could easily find...a lot of the markets that we thought might be useful as offtakers” for U.S. supply could close up, at least temporarily.