Natural gas July forward prices rose a nickel on average, although uncertainty about long-term weather trends and current mild weather in most of the country left several markets in the red for the June 6-12 period, according to NGI’s Forward Look.

Gains and losses at the vast majority of market hubs were limited to less than a dime, a trend also seen along the Nymex futures curve. The July contract steadily rose -- albeit very slightly -- from Friday to Tuesday, but then retreated a bit Wednesday after some of the latest weather data backed off its earlier warmer shift.

The July Nymex contract ultimately rose 6.2 cents from June 6-12 to reach $2.386, with similar gains seen for the August and balance of summer (July-October) contracts.

The overnight Wednesday weather data took a bearish turn as both the American and European models trended slower with the return of ridging into the South and East, according to Bespoke Weather Services. The models still showed such a pattern at the end of outlooks, but “for now it appears to be just a timing change in the modeling as opposed to a fundamentally different pattern,” Bespoke chief meteorologist Brian Lovern said.

By Friday, however, both models were back on board with returning heat, especially for the last week of June, when coverage of high temperatures in the 90s and, in some cities, low 100s was on tap for much of the country.

Meanwhile, all eyes were on Thursday’s Energy Information Administration (EIA) storage report, which turned out to be the sixth triple-digit storage injection in a row. The EIA reported a 102 Bcf injection into storage inventories for the week ending June 7, which was slightly smaller than expected but in the broader range of estimates. Most projections had clustered around a build near 110 Bcf, with NGI estimating a 108 Bcf injection.

The injection was larger than both last year’s 95 Bcf build and the five-year 92 Bcf average injection. The storage data provided an initial modest uplift for natural gas futures prices, trimming earlier losses by around 1.5 cents. However, it didn’t take long for traders to digest the storage data, and prices quickly resumed their slide. The July gas contract ultimately settled Thursday at $2.325, down 6.1 cents. August fell 5.9 cents to $2.322.

With prices remaining in the red, there was further downside risk ahead, according to Flux Paradox LLC President Gabriel Harris.

“The three-day natural gas price rally Friday through Tuesday just set up the market for a short opportunity,” Harris said on Enelyst, a chat room hosted by The Desk. “I don’t think we’re done exploring new price lows yet. I think new lows will come as the supply/demand balance is still loose.”

Thus far, lower prices have not made the weather-adjusted injections look any tighter, which starts to cause reasonable doubt in the market on the whole coal-to-gas switching mechanism, according to Harris. “The market will need dramatic evidence that the price-switching mechanism is at full strength before a bottom occurs.”

However, Bespoke said balance wise, the 102 Bcf injection was considerably tighter than the previous week’s loose 119 Bcf print, giving the firm more confidence in the data after the previous two big misses. The firm said the tighter balances should show up in the upcoming storage figures as well, although with such low demand week during the second week of June, “we could still see another triple-digit build.”

By region, the Midwest reported a 33 Bcf injection into inventories, while the East added 26 Bcf, according to the EIA. Stocks in the Mountain region grew by a larger-than-expected 10 Bcf, and stocks in the Pacific rose by 14 Bcf.

Working gas in storage as of June 7 stood at 2,088 Bcf, which is 189 Bcf higher than a year ago but still 230 Bcf below the five-year average, according to EIA.

Fundamentally speaking, Raymond James & Associates Inc. has a bearish outlook on natural gas, which is modestly supported by its expectations for strong natural gas demand and export trends. Although project delays are affecting some near-term gas demand from liquefied natural gas (LNG) and Mexican exports, “the fact remains that U.S. gas demand growth is very stout from coal-to-gas switching, petrochemical expansions, LNG exports, and Mexican exports.”

However, the upcoming gas supply surge, particularly from associated gas production, should more than offset robust demand growth, according to the firm. “Given the high degree of associated gas production generated by some of the largest shale oil plays, U.S. natural gas prices now relate inversely to oil prices, thereby driving gas lower.”

In the near term, a gas price decline is necessary to stimulate sufficient coal-to-gas switching activity to rebalance the market, according to Raymond James. Longer term, with associated gas production remaining robust, the market needs only modest supply growth from Appalachia (and likely declines in most other gas plays) to balance.

“We expect 2019 should prove to be a positive year for natural gas demand as both exports to Mexico and outbound LNG tanker activity ramp up. On the supply side, more associated gas supply is expected,” the firm said. “However, we believe an increasing domestic gas supply and growth in renewables that are increasingly becoming more cost competitive with gas are putting further pressure on Henry Hub gas prices.”

California Softens Despite Heat

Much of the United States enjoyed rather mild weather during the June 6-12 period, but the West Coast was scorched by record temperatures. The recent heat wave sent temperatures soaring up to 30 degrees above average into the 90s and over 100 in some coastal areas from California to Washington, shattering record highs, according to AccuWeather.

The strong demand lifted power generation throughout the Western Electricity Coordinating Council area by 1,023 GWh from June 11 to June 12, with gas leading the way among the different fuels in the stack, according to Genscape Inc. Meanwhile, total demand on the Pacific Gas & Electric Co. (PG&E) system crested the 2 Bcf/d mark for the first time this summer as temperatures in the San Francisco Bay Area topped 100 degrees, setting new record highs.

Power supply had been temporarily cut during the June 8-9 weekend to thousands of PG&E customers as a precautionary measure against wildfires, but it did not make a dent in overall demand. “Power prices reportedly topped the $1,000/MWh mark and noncore electric demand for gas hit 876 MMcf/d, a mark not reached last summer until mid-July,” Genscape senior natural gas analyst Rick Margolin said.

Farther south, aggregate demand in the Southern California region (Southern California Gas plus El Paso Natural Gas and Kern River Pipeline/Mojave Pipeline) had climbed to a summer-to-date high of 3.6 Bcf/d, also a mark not reached last summer until July, according to Genscape.

Traders, however, appeared to disregard the current heatwave, sending forward prices in Southern California lower across the curve as outlooks showed a more seasonal weather pattern returning to the region beginning this past weekend.

"A more typical weather pattern that favors a persistent sea or bay breeze with areas of morning low clouds is in store along the coast," according to AccuWeather senior meteorologist Brett Anderson.

The pattern, known to locals as "June gloom" was expected to ramp up and spread northward, the forecaster said. Temperatures were forecast to hover within a few degrees of average along much of the California coast.

Highs were expected to generally range from the middle 60s to the lower 70s along the California and southern Oregon coasts and the 70s along the northern Oregon and Washington coasts.

Given the much milder outlook, SoCal Citygate July fell 11 cents to $5.403, while August slid a penny to $5.594 and the balance of summer (July-October) dropped a nickel to $4.73, according to Forward Look.

Forward prices in far less volatile northern California held relatively steady during the June 6-12 period.

Nevertheless, the expected drop in demand took a toll on prices in the Permian Basin, which relies on downstream demand in California. El Paso-Permian July fell 4 cents to average just 45.6 cents, as did August, which hit 86.1 cents. The balance of summer was down just 2 cents to $1.06, and the winter strip (November 2019-March 2020) was flat at $1.99, Forward Look data show.

Elsewhere across the country, ANR SW forward prices came off at the front of the curve amid a vastly improved storage picture. As of Thursday, ANR Pipeline had 82 Bcf in storage, which is 20 Bcf greater than inventory levels at this time last year but still 15 Bcf shy of the five-year average, according to Genscape.

“ANR Pipeline is having a notably strong injection season though, posting total injections of 39 Bcf during the months of April and May. This can be compared to total April and May injections of 29 Bcf in 2017 and only 15 Bcf in 2018,” Genscape analyst Anthony Ferrara said. “If this trend continues, as we are seeing so far in June, ANR Pipeline inventory levels could reach back up to the five-year average for the first time since December 2017.”

ANR SW July prices dropped a nickel from June 6-12 to reach $1.651, while August slid 2 cents to $1.746 and the balance of summer shed a penny to hit $1.72. The winter strip rose 1 cent to $2.35, Forward Look data show.