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PJM market monitor says average LMP increased 23% in 2018 as gas overtook coal

In a historic first for America's largest wholesale electricity market, natural gas-fired power generation in 2018 exceeded coal-fired generation across the footprint of the PJM Interconnection, according to the grid operator's independent market monitor.

Monitoring Analytics LLC's newly released "2018 State of the Market Report for PJM" observed that overall generation across PJM's market increased 3.6% to 837,648 GWh in 2018 from about 808,230 GWh in 2017. PJM's footprint extends across the territory of 13 states in the Midwest, Mid-Atlantic and South as well as the District of Columbia.

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At a March 14 media briefing in Washington, D.C., Monitoring Analytics President Joseph Bowring said 2018 notably saw natural gas-fired megawatt-hours exceed coal-fired megawatt-hours in PJM "for the first time ever."

While nuclear power remained the largest fuel source for PJM by generating a slightly smaller 34.2% of the region's electricity in 2018 (down from 35.6% in 2017), coal's share of the market fell 6.6% from 2017 to constitute 28.6% as natural gas' share increased 18.2% to generate 30.9% of PJM's electricity for the year. Renewables' share remains quite small in PJM in 2018, Bowring noted, with wind coming in at 2.6%, hydropower at 2.3% and solar at 0.3%.

The total price of wholesale power across PJM increased 17% to $62.30/MWh in 2018 from $53.24/MWh in 2017, while total billing increased 22% to $49.29 billion in 2018 from $40.40 billion in 2017. Breaking the numbers down, Bowring said load-weighted energy costs increased 23.4% from the previous year, in comparison to capacity prices that increased 15.5% and transmission prices that decreased 0.8%. Further, load increased 4.3%, the largest increase since 2012, which Bowring attributed to weather.

In addition, congestion costs on PJM's transmission lines increased 87.8% in 2018 from the previous year, according to the report.

Real-time, load-weighted, average locational marginal pricing increased to $38.24/MWh in 2018 from $30.99/MWh in 2017. "2016 was the lowest LMP in history of PJM and 2017 was the next lowest but in 2018 energy prices increased quite significantly and they increased to a level that we haven't seen since 2014, the year of the polar vortex and more-or-less comparable to 2013," Bowring said.

Bowring said the monthly LMP pattern shows relatively low prices. He also noted that coal still has a significant presence in PJM and even sets prices about 25% of the time. While PJM's energy markets were viewed to be competitive in 2018, Bowring said its capacity market was not competitive due to flaws in its design that include PJM's capacity cap offer and its 30-hour performance assessment requirement.

Concerning the financial health of generating units within PJM, the IMM report shows that while nearly every gas-fired and hydro facility fully recovered its avoidable costs from all markets in 2018, only 63% of coal-fired units did so, up from 36% in 2017. In comparison, 84% of nuclear power units recovered all of their avoidable costs in 2018, up from 53% in 2017.

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Looking forward, the IMM predicted that PJM's nuclear fleet — except the single units at FirstEnergy Corp.'s Davis-Besse and Perry plants in Ohio and Exelon's Three Mile Island facility in Pennsylvania, all of which are seeking early retirements — will continue to cover their avoidable costs and also bring in revenue, albeit in expected declining amounts through 2021. Nonetheless, Exelon recently warned that its Braidwood, Byron and Dresden nuclear power plants in Illinois are "showing increased signs of economic distress, which could lead to an early retirement." All or portions of those plants failed to clear PJM's latest capacity auction, and recent S&P Global Market Intelligence data analysis indicated that the operating costs of the three plants are running close to wholesale electricity prices.

Excluding zero-emissions credit payments that Exelon Corp.'s majority-owned Quad Cities receives from Illinois, the IMM report also forecast that the 1,819-MW facility will receive a surplus of $3.56/MWh in 2019 before falling to $0.90/MWh in 2021. For the market monitor, those forecasts show that Quad Cities did not need the zero-emissions credits to continue to operate, Bowring said.

Bowring recalled that he cited such forecasts in his testimony before a March 13 caucus of Pennsylvania lawmakers and urged them not to pass legislation to give out-of-market financial help to nuclear power plants such as the 829-MW Three Mile Island and FirstEnergy Solutions Corp.'s 1,872-MW Beaver Valley nuclear plant, which are slated to shut down in September 2019 and in 2021, respectively. Beaver Valley is expected to have an annual surplus of $5.39/MWh in 2021, according to the IMM report.

"There is only one unit in Pennsylvania which is at risk; that's TMI," Bowring said. "Providing subsidies is a bad idea. ... Subsidies are inconsistent with competitive markets. We've seen we have plenty of capacity. We don't need any particular unit … [that] can't compete."

Along with the three at-risk nuclear units, the IMM also identified 24 coal-fired units at risk of retirement, with a total combined at-risk capacity of 14,954 MW.