Natural gas prices crested the $4.00/MMBtu mark last week, and though the gains may have come quickly, price may need to be higher to incentivize more coal in power generation to help balance the market, according to Raymond James & Associates Inc.

Raymond James

Coal’s share of the power generation stack would have to increase by more than 3 Bcf/d year/year in order to achieve this, Raymond James analysts said in a note to clients Monday. Whether the power market has the capability to achieve this, however, is the “biggest point of contention” among investors.

U.S. gas prices have had a “huge summer,” said analyst team led by J.R. Weston. The New York Mercantile Exchange 2021 strip has rocketed higher, largely on more constructive weather. While domestic liquefied natural gas (LNG) has recovered from 2020’s pandemic-induced lows, production also experienced a significant rebound. This has helped to offset the gains in exports.

“While the ‘return to normalcy’ was a bit quicker than we modeled last year, producer discipline and limited incremental U.S. Northeast pipeline takeaway capacity should keep a lid on the supply response,” Raymond James analysts said. “With this context, we still think price-induced demand headwinds are necessary to keep year-end U.S. natural gas inventories at ‘normalized’ levels in both 2021 and 2022 — not drifting too far below 4 Tcf.”

As such, the analyst team is modeling 2021 Henry Hub prices to average $3.50, up 13% from its prior forecast. Prices in 2022 are projected to average $4.00, up 20%.

The Energy Information Administration (EIA) similarly raised its Henry Hub price outlook. In the July edition of the agency’s Short-Term Energy Outlook, the EIA said it is raising its projected average Henry Hub spot price to $3.21 for 2021, a 14-cent increase over the previous month’s projections.

Even then, the Raymond James analysts said the argument could be made that U.S. inventories at that level might still be too low. With LNG exports increasing more quickly than nationwide storage capacity, days of inventory in the U.S. natural gas market are getting increasingly tighter.

As of July 16, total working gas in U.S. storage facilities was at 2,678 Bcf, which was 532 Bcf below year-ago levels and 176 Bcf below the five-year average, according to EIA.

Coal To The Rescue

The Raymond James team sees the economic switching between coal and gas remaining the key variable in balancing the market. The analysts, including John Freeman and senior research associate Graham Price, noted that in 2020, coal accounted for only 19% of the power stack, down from 33% in 2016.

The International Energy Agency also noted earlier this month that sharply higher energy demand has given coal the edge this year.

In the last two years, natural gas has made up for much of that lost coal generation, especially as Covid-19 decimated export demand and helped send Henry Hub prices down to around $2.00, a “very competitive position” relative to coal across essentially every U.S. power market, the Raymond James analysts said. In response, peak U.S. gas power burn exceeded around 45 Bcf/d and averaged roughly 39% of the annual electric generation mix at a record 31.6 Bcf/d (up 0.7 Bcf/d year/year).

With prices now up about 50% year/year, the analysts estimated that there’s around 2 Bcf/d of switchable capacity up to around $3.50 — and another roughly 1 Bcf/d if natural gas prices rise near $4.00 or more. However, they noted that there’s been debate about how much switchable capacity remains following the wave of coal retirements in recent years.

The United States has shut down nearly 30% of its coal capacity since 2010, taking it down to around 235 GW today. However, “the U.S. still has substantial coal plant capacity.”

The firm noted that roughly 15-20% of total capacity in the United States is switchable, but there are regional differences in how much gas can be replaced with coal. The Midwest and Northeast have the most switchable capacity at around 0.7 Bcf/d each with replacement natural gas prices of more than $3.00u.

Interestingly, the Raymond James analysts said Texas would likely be one of the areas that sees the most switching away from natural gas, not only because of coal, but also the proliferation of wind and solar within the state. On the flip side, the New York City metropolitan area could see increased gas power burn “almost regardless” of gas pricing dynamics because of the retirement of the Indian Point nuclear plant in April. Regional prices for both coal and natural gas also could influence switching.

“Make no mistake, in a scenario with extreme pricing in the $4 range in the back half of this year, power generation should dramatically move away from natural gas — but not nearly to the degree we had previously anticipated,” Raymond James analysts said.

For now, the analysts “still feel comfortable” with a slight decline in gas-fired generation to around 38% this year, “certainly a meaningful change relative to our prior model.” While solar and wind are set to continue encroaching on coal’s “normalized” market share, coal should also see a modest increase in generation share in 2021 because of higher gas prices. With gas prices expected to stay elevated in 2022, the firm expects natural gas market share to recede slightly yet again.

However, if coal were unable to take sufficient power generation market share from natural gas this year, then Raymond James analysts said even higher prices would be warranted in order to drive changes in supply/demand balances. This could come in the form of slowing industrial and commercial demand, more incremental renewables competition, accelerating imports of gas from Canada or the slowing of U.S. LNG exports and pipeline exports to Mexico.

“The other alternative would be to simply draw inventories throughout 2021 by a substantial degree – creating longer-lasting optimism for natural gas prices,” the Raymond James analysts said. “This is very obviously a ‘bad outcome’ in terms of the ‘health’ of the overall U.S. natural gas market, but would be ‘good’ for natural gas prices at face value.”

High Pain Tolerance

Energy Aspects similarly noted the inability of gas prices to more discernibly reduce the share of gas in the power stack so far. The consultancy’s team said the market may need to wait until the fall season for that to happen. Overall loads by that time would likely be lower and the market requires less gas to chase afternoon peaks. However, the firm noted that with gas prices around $4.00, the market would still only be backing out gas in power generation, as industrial and export demand have a much higher price point before they start “feeling pain.

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“Given the slim supplier and customer inventories in light plastics and other segments of gas-intensive industrial demand, we do not expect higher gas prices for fuel/feed gas to stop manufacturing,” the firm said. “Increased costs are likely to be passed on to end-use customers instead.”

Additionally, only a small component of gas-fired electric generation in Mexico may be substituted back to fuel oil, according to Energy Aspects. Meanwhile, Mexico appears to have actually increased its reliance on U.S. gas this summer, hitting an early record before the summer season got underway.

In a “truly” price-sensitive scenario, Energy Aspects said the 0.2-0.3 Bcf/d of fuel oil could be substituted back into the power sector, which would make shutting off any additional exports dependent on how much other demand Mexico has for that gas. Piping gas to Mexico would still be more cost effective than LNG, according to the firm, especially with the wide arbitrage levels between Henry Hub and European and Asian prices.

“The ability to take high-priced gas would then depend on whether industrial customers in Mexico would pass on costs for fuel as similar firms do in the U.S., especially as these industrials typically bear the costs of system balancing many times when total Mexican linepack is suboptimally low.”