Gas-Fired Power Gen Still Strong in Face of Price Rise

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Natural gas-fired generation in the US remains strong in the face of rising gas prices, implying that the market may finally discern the ceiling on price driven gas-to-coal switching in the power sector. “In the first half of 2020, natural gas made up a 69% share of fossil fuel generation and Henry Hub prices averaged $1.81/MMBtu. For the same period in 2021, natural gas made up a 60% share of fossil fuel generation, and Henry Hub prices averaged $3.25/MMBtu," the US Energy Information Administration (EIA) said last week in its Short-Term Energy Outlook. "Since March 2021, the Henry Hub price has steadily increased, approaching $4.00/MMBtu, yet the natural gas share of fossil-fuel generation has remained higher than 60%.” Rising gas prices typically lead gas-fueled generation to cede market share to cheaper coal. But the nation’s coal-fired generating capacity has declined every year since 2011 while facilities have added gas-fired capacity every year since at least 2009. The only regions left with substantial price-sensitive coal capacity are the PJM Interconnect, which includes gas-rich Appalachia, and the Midcontinent Independent Service Operator (NGW Oct.5'20). Yet Tudor Pickering Holt (TPH) analysts said last week they expect gas-fired generation should account for around half of US thermal generation during the impending shoulder season despite gas prices hovering at multiyear highs. “We’ve observed through the summer an inability for coal generation to breach the 3.4 terawatt hour level [3.4 million megawatt hours] -- a cap on our forecast for generation which limits gas' share of thermal generation to 52%,” the analysts said. And the EIA said that makes decisions about whether to dispatch a gas-fired plant less responsive to price signals. Despite increasing the forecast price generators will pay in the third quarter by 14% to $3.88/MMBtu, the EIA forecasts gas-fired generation will supply 429 TWh, or 60.8% of the nation’s 705.4 TWh fossil fuel generation in the third quarter, up from the 416 TWh, or 58.9% of 705.8 TWh in the prior outlook. The third-quarter figure represents 47.2% of thermal generation, up from 45.7%. Fuel-switching dynamics led TPH analysts to revise their end-of-season storage balance to about 3.6 trillion cubic feet from around 3.5 Tcf. “We see modest potential pricing risk toward the $3.75/MMBtu range for September-October, but generally fundamentals remain supportive for a tight market into winter, with potential risk to the upside in winter if weather proves colder than normal,” the analysts said. Their storage forecast is in line with that of the EIA, which predicts storage levels will reach 3,592 billion cubic feet, or 159 Bcf below the five-year average, by Nov. 1, with above-average withdrawals during the winter heating season, below-average injections during the summer, low dry gas production growth, and elevated exports as the main inventory drivers. According to the EIA, US gas exports via pipelines and LNG terminals will average 18.38 Bcf/d, a 27.3% increase versus the prior year, while marketed production will average 1% higher at 99.81 Bcf/d. During the first half of the year, average US LNG exports grew 2.8 Bcf/d, or 42%, year over year from rising demand in Asia, government data show. Meanwhile, gas earmarked for exports last week, including 6.7 Bcf/d piped exports to Mexico, averaged around 16.3 Bcf/d, while dry gas production remained close to 93 Bcf/d, the EIA said. Contract Dips Under $4 September gas futures had a rough week, decisively losing its $4 handle by the weekend. The contract broke through key $4 psychological support Thursday, plunging 12.6¢ to $3.933/MMBtu. This was followed by a 7.2¢ retreat on Friday to end the week at $3.861/MMBtu. The contract began to wobble earlier in the week as an outlook for more moderate cooling loads capped the recent rally in the $4-teens. The EIA reported a 49 Bcf injection into storage during the week ended Aug. 6, bringing working gas inventories to 2,776 Bcf. The injection, in line with expectations, was higher than the 42 Bcf five-year average but below the 55 Bcf build seen during the same week last year. The build lowers the deficit to the five-year average to 178 Bcf, or 6%, and puts the deficit to a year ago at 548 Bcf, or 16.6%. Early estimates for the week ending Aug. 13 average 26 Bcf, with models ranging from 9 Bcf to 45 Bcf. That compares to a five-year average build of 42 Bcf and a year-ago injection of 45 Bcf. “Last week’s relatively large injection appears to be the exception in the next few reports and the pace of storage builds will remain under pressure in the coming weeks,” Gelber & Associates analysts said. Everett Wheeler, Washington, and Tom Haywood, Houston

Gas Demand, Gas Inventories, Coal, Gas Prices
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