North America is swimming in natural gas and global demand still lags, but within a few months, opportunities are expected to open up as Gulf Coast and Western Canada exports expand and storage levels decline.
Relief is coming to cut into the surfeit of storage, but it’s unlikely to happen before 2025, energy experts said at the LDC Gas Forums Rockies & West conference in San Diego. East Daley senior energy analyst Alex Gafford discussed the opportunities and challenges ahead with NGI’s Leticia Gonzales, managing director of North American natural gas pricing, and with NRG Energy Inc.’s Chet Sharma, natural gas fundamentals analyst.
Winters have been warmer than normal. Greenfield and expanded LNG export projects, some promised to start up this year, have been delayed. Associated natural gas from Permian Basin oil wells is being burned off because of a lack of takeaway and negative pricing.
“The first half of 2024 has been pretty rough for gas markets,” Gafford said. “We’ve seen average production fall about 1.5 Bcf/d from 2023 levels.”
Abundant gas storage exists from the Western Canada Sedimentary Basin (WCSB) to the Gulf Coast and on to the West Coast. A mild winter pressured stocks. A series of maintenance issues at Freeport LNG, the liquefied natural gas export project in Texas, shuttered some export capacity for weeks. And European demand has fallen, cutting into the need for domestic exports.
“Unsurprisingly,” Gafford said, some of the big, gassy U.S. exploration and production (E&P) companies have dropped rigs, reduced output and shut in wells. Still, prices have barely budged. Storage too has barely budged.
There are “more conservative drilling programs due to a lack of gas egress,” Gafford said. “Unfortunately, we have not declined enough…We risk ending the season at the highest level we’ve seen in the last five years. We currently expect ending October storage at around 3,884 Bcf/d.”
Natural Gas Imperative
Could the golden age of natural gas be ending? Not even.
“I don’t think our energy needs are ever declining,” Gonzales told the Southern California audience. “Do we need renewables? Absolutely. But…we need an all-of-the-above approach to meeting rising energy demand.”
Critically, “we still need to have the baseload” provided by natural gas. “All of it is needed for reliability.”
Gonzales illustrated the bumpy road for the domestic gas market using what has happened in Southern California. There, “prices are averaging at only a 32-cent premium over Henry Hub this year…In 2023, that premium was $4.21/MMBtu.”
California prices were even higher in 2022, when the Pacific region had become limited in serving local demand and balancing daily inflows, in part because of a sharp reduction in storage capacity. There also were infrastructure challenges.
Working gas at the state’s largest underground gas hub, Aliso Canyon in Southern California, was reduced following a multi-month well failure in 2015. Meanwhile, Pacific Gas & Electric Corp. (PG&E) in June 2021 reclassified 52 Bcf to base gas from working gas.
Together, the events heightened volatility.
Pacific storage has since recovered, aided in part by a mild winter and as renewables generation has escalated. Today, Southern California Gas stocks are “22% over the five-year average,” Gonzales noted. “PG&E inventories are 13% below the five-year average, but 119% above the three-year average, excluding reclassification.”
With more renewables backing up the grid, are the concerns about volatility in the natural gas markets overstated?
“Natural gas is still critical to maintaining the electric grid,” Gonzales said. “U.S. power burns are still setting records, despite repeated projections for lower gas demand…”
The U.S. Energy Information Administration, for example, called for gas demand to peak in 2021, “but it hasn’t happened yet…We’re seeing power burns setting records…going on three years…
“We can’t sit idle and hope for the best. The forward market is pricing in some risks, but one-off events could add to the volatility…We’re not going back in time. Our energy needs are not declining…With renewables being intermittent, we need a backbone to maintain the power grid and ensure reliability,” she said.
NGI’s Forward Look shows California forward prices averaging around $5.15 for the upcoming winter at PG&E Citygate, and around $5.32 at SoCal Citygate. Henry Hub winter prices, meanwhile, are seen averaging around $3.16.
Gafford said the gas markets have to remain vigilant. “A large hurricane or some weather event” could take an LNG export project offline on the Gulf Coast, as happened with Freeport. That “could easily push us to oversupply that really strains existing infrastructure and drives services significantly lower.”
Still, a “short-term price headache begets healthier prices in 2025,” the East Daley analyst said. “The current low price environment should discourage a run-up in production until more demand shows up.”
And that demand is indeed set to show its face in 2025.
Canadian LNG ‘Poised To Take Off’
The Gulf Coast has expansions and greenfield projects nearing completion. In British Columbia, Canada’s first LNG export project is set to debut as the Shell plc-led LNG Canada project begins sending cargoes to Asian markets.
Canadian gas exports are “poised to take off,” Sharma told the LDC audience. The WCSB could provide “6-7 Bcf/d of export capacity by decade’s end.”
The Canada gas export queue includes two greenfield projects underway, Cedar LNG and Woodfibre LNG. Preliminary work on the floating Ksi Lisms LNG Ltd. project is advancing toward a final investment decision. And LNG Canada is proposing an expansion.
“Unlike in the Lower 48, there’s been no significant pullback in production,” Sharma noted.
“Receipts hold steady” on TC Energy Inc.’s NGTL System, which moves most WCSB gas. “Rigs have declined,” but there are “still 120 wells completed monthly.”
Canadian E&Ps working in the gassy Montney Shale have barely budged as lower prices have roiled the U.S. gas markets.
“I think it boils down to three main things,” Sharma explained. First, the Montney’s breakevens are some of the lowest in North America.
“Second, there’s a lot of liquids-weighted production in the Montney,” he said. The natural gas liquids can be sold off, driven by stronger Western Canada Select and West Texas Intermediate oil prices.
The “most important factor,” though, is that the top gas producers, led by Tourmaline Oil Corp., have “a lot of exposure outside of AECO,” Sharma said. “Their realized price is well above what AECO trades at.”
NGI’s NOVA/AECO C averaged at only C$88.0/GJ cents for August, according to NGI’s Bidweek Survey. What’s more, this was up 14.5 cents from the July bidweek price. Prices at the Western Canada benchmark have averaged only 69.6 cents this month to date.
Still, “history tells us to prepare for a volatile market,” Sharma said. There is “no significant basis upside being priced in further out.” The AECO hub “is bursting at the seams…It has only recently started to feel like summer.”
A “slight upside in intraprovincial demand” should come this winter. TC’s Gas Transmission North West XPress Project is eyeing a year-end ramp to expand capacity to around 2.9 Bcf/d from 2.7 Bcf/d.
“That will ease pressure in Alberta,” Sharma said.
The expansion of the Trans Mountain Pipeline (TMX) crude oil conduit, commissioned in May, also will help the gas markets. TMX moves heavy oil from the oilsands developments to export markets. Western Canada’s biggest user of natural gas is the oilsands sector.
“The start up of TMX, along with a bullish oil market, will lead to growth in industrial gas demand in the oilsands,” Sharma said.
Meanwhile, there has been a “ton of migration” to Alberta. As in the Lower 48, there’s also a lot of talk in Calgary about building data centers to house artificial intelligence. That will take some gas generation, Sharma said.
“TMX could lead to 0.5 Bcf/d gas demand,” the NRG expert said. Data center load growth, queued up to begin operation by 2030, could require 3 GW in the WCSB.
“It’s not huge like the Lower 48, but it’s not nothing.”
