Low salt stocks risk a repeat of a natural gas price spike if there is early cold weather, leading analysts with BofA Merrill Lynch Global Research to increase the average New York Mercantile Exchange price forecast for this coming winter to $3.00/MMBtu.

The firm kept intact its overall 2020 price forecast of $2.60/MMBtu as supply growth should match liquefied natural gas (LNG) expansions next year, leaving the market in surplus.

“Waning LNG growth and more renewables” capacity are driving an initial 2021 forecast of $2.40, but continued discipline by the exploration and production (E&P) sector should keep the back end from crashing, analysts said.

Low salt stocks ahead of last winter contributed to the price spike, and unless the inventory builds increase, the market risks a repeat of early cold weather that would push prices higher later this year, according to BofA Merrill’s analysts.

“Late last year, the 2019 strip rallied to nearly $3.30/MMbtu, but it took 1Q2019 pricing over $4.00/MMbtu in order to do so. We are not as optimistic about peak winter prices this year due to higher overall inventories, although our $3.00/MMbtu winter price forecast is 19% above the forwards. Even then, too much gas past peak winter keeps pressure on next summer and allows us to maintain our $2.60/MMbtu price projection for the 2020 strip.”

The United States today is exporting record gas volumes, both via LNG and through pipelines to Mexico. Still, the oversupply continues to linger on massive Lower 48 growth, mostly from associated gas from the Permian Basin.

“The real problem, in our opinion, is not the LNG export capacity growth over the next year, but is instead the lack of LNG capacity additions in 2021-2023,” analysts said. “In addition, renewable energy could provide headwinds for power sector natural gas demand.”

Volatile oil prices, in combination with underwhelming gas and natural gas liquids (NGL) prices, may help E&Ps continue transition to moderate growth -- and better cash returns, the BofA Merrill analysts said. Increased infrastructure additions also should support Permian development, even with more capital discipline.

“Even if overall Permian development slows, more than 60% of the drilling activity in the basin targets the Delaware,” which with the Midland is considered one of the twin sub-basins. “This split is important from a natural gas perspective since the average Delaware well produces over twice as much associated gas compared to an average Midland well.”

By late September, the 2 Bcf/d Kinder Morgan Inc.-led Gulf Coast Express pipeline should provide a big relief valve for Permian gas. “But given the significant natural gas pipeline capacity planned for late 2020 and 2021, long-term Permian gas basis could be at risk of tightening, especially if producers continue to moderate growth in search of free cash flow.”

Permian Oil, NGL ‘Slowdown Pressure’

Wood Mackenzie’s Eugene Kim, research director of Americas Gas, said the rapid increase in Permian associated gas output has placed “increasing slowdown pressure” on oil and NGL streams. He was speaking at the Unconventional Resources Technology Conference in Denver.

“Permian production is ramping up, but midstream bottlenecks across oil, gas and NGLs may force a slowdown, as all three production streams are interrelated, and any midstream constraints impacting one will impact all,” Kim said.

“In particular, natural gas is becoming the weakest link that prevents monetizing growing Permian Basin supply. With Permian Basin gas production continuing to grow, the market will feel every little hiccup in takeaway capacity, and negative pricing will be a more common occurrence.”

Kim predicted more gas flaring of associated gas could be necessary if infrastructure construction delays “translate into lower Mexican gas exports from Waha, or Permian producers may need to back down from their growth trajectory until more pipeline takeaway capacity is available.”

Permian oil takeaway faces a different dilemma, with an overbuild in the near term to the Gulf Coast, “leading to an average pipeline utilization of just 64% in 2020,” according to Kim. The situation should shift by 2025, as production growth fills existing infrastructure and the average utilization moves to around 84%.

More than 2 million b/d of greenfield pipeline capacity is likely to come online in the next year near Corpus Christi on the south Texas coast, which would improve volume takeaway from the Permian. However, the expansion threatens to surpass the region’s estimated marine terminal export capacity.

The Port of Corpus Christi, about 200 miles south of the energy capital of Houston, is expected to emerge over the coming decade as the nation’s No. 1 crude export hub.

“The key market impact to watch in the first half of 2020 will be if the bottleneck for Permian producers simply moves 600 miles down the road into Corpus Christi, and congestion occurs in getting crude on the water for export,” Kim said.

Like crude, incremental NGL takeaway pipeline capacity slated to come online by late this year also runs the risk of an overbuild.

“However, the rising gas/oil ratio and increasing gallons/Mcf both provide upside risk to Permian Basin NGL production that may potentially require even more takeaway pipeline capacity.”