When it comes to natural gas demand in the U.S., there’s good news and bad news if you ask Mark Finley, an energy and global oil fellow at the Center for Energy Studies at Rice University’s Baker Institute.
“The bad news is there’s still a lot of capacity to switch back and forth between coal and gas in power generation in the United States. … There’s a lot more competition for other fuels—at least in the short term,” Finley said during a recent webinar on the future of U.S. shale. “The good news is there’s a global marketplace the U.S. producers can access through LNG.”
Among the lingering questions is whether the global demand will be large enough to uplift the U.S. Will companies with gas-weighted portfolios grow gas production? How could associated gas production impact plans?
The natural gas sector, like oil, faces uncertainty. The pace of economic recovery remains in flux as the world continues to cope with the COVID-19 pandemic and falling demand amid a renewable energy push.
Having seen prices nosedive from more than $13 per million Btu to less than $2.40 in the last 15 years with occasional dips and spikes, the U.S. natural gas sector’s rollercoaster ride continues. Production has gone from being in decline to abundance as the shale revolution unfolded, enduring several downturns along the way.
Unlike oil prices, gas prices never recovered from the collapse in 2008-2009, said Ken Medlock, senior director for the center and webinar moderator. The oil price recovery in the years since “really helped to kind of stoke growth in gas output more generally in the United States” as associated gas from oil-directed drilling added to plentiful supplies.
However, the oil and gas sectors are struggling. Medlock questioned what the future could hold for gas producers, particularly in a world where oil production could suffer.
“This is, we hope, the last year that we were going to have a negative forecast for natural gas,” said Matt Portillo, managing director of upstream research for Tudor, Pickering, Holt & Co.
“We came into the year quite bearish on the fundamentals, which had to do with where the balances were, as well as our concerns that the global market from an LNG perspective was quite oversupplied given where European inventories were,” Portillo said. “What we saw was a very significant pullback through the summer on LNG exports, and we’ve seen a fairly significant decline in the U.S. in aggregate gas production.”
Gas production from major basins in the U.S. is expected to fall by 428 million cubic feet per day to nearly 80.6 billion cubic feet per day in October, data from the U.S. Energy Information Administration’s (EIA) Drilling Productivity Report show.
Entering 2020, the aggregate gas volume was about 96 Bcf/d, Portillo said. Given legacy basin declines in places such as the Barnett, Fayetteville and Pinedale along with declines in associated basins, he said the U.S. will exit the year in balance with about 89-90 Bcf of supplies.
Natural gas inventories had shown year-on-year increases since April 2019, the EIA said. However, that trend is expected to reverse. Production is forecast to decline through March 2021 with average production next year about 3.3 Bcf/d below 2020 levels.
Producers are trying to mitigate declines. Many have reduced spending. Some have shifted to new strategies with the energy transition in mind. And others have moved toward a dividend distribution and a free cash flow distribution model, Portillo said.
“There’s not a lot of incentive for growth,” he added.
Even in a $2.75 to $3 gas world, Portillo said he does not expect to see much incremental dry gas production coming from the Northeast or the Haynesville over the next few years.
“When you have 40 Bcf a day supply coming out of those two basins, producers don’t have a lot of wiggle room to grow,” the analyst said. “If you get into a situation where every E&P individually raises their hand and says, ‘I would like to grow 4 or 5% per annum,’ all of a sudden you’re pushing somewhere between 1.6 and 2 Bcf a day of gas supply into the market.”
Add associated gas from oil growth of about 300,000 to 400,000 bbl/d to the scenario, and the supply stack increases by about 1 Bcf, according to Portillo’s estimates.
“Producers are aware of that. They understand that the reason that gas has partially gone from 13 down to 1.50 at one point this year was the unending growth and the associated market’s impact on that,” he said. “And I think you’re seeing a structural shift again behaviorally around the gas markets.”
Higher prices could, however, be on the horizon, considering the decline in inventories forecast by the EIA. Its outlook shows Henry Hub spot prices averaging $3.19/MMBtu in 2021. That’s about $1.02/MMBtu higher than in 2020.
“I think the big question there is what happens coming on the back end of COVID, which, of course, opens the door to a lot of conversations about energy transition and shifting energy mixes in different places around the world,” Medlock said.
Although the EIA forecasts U.S. consumption of natural gas to fall 2.7% to 82.7 Bcf/d in 2020 and to 79.1 Bcf/d in 2021 as natural gas prices rise, the outlook shows U.S. LNG exports will rise and return to pre-COVID levels by November.
Rising global gas prices in Asia and Europe in August led to U.S. LNG exports increasing to 3.7 Bcf/d in August from a 21-month low of 3.1 Bcf/d in July. The EIA forecasts LNG exports will average more than 9 Bcf/d from December 2020 to February 2021.
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