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PJM board to guide next steps on capacity market design change

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PJM board to guide next steps on capacity market design change

A PJM Interconnection board meeting scheduled for Feb. 14 is expected to provide direction on how the region's power markets can remain competitive and still accommodate resources paid by states.

Like other regional power markets, PJM's are designed to select the most economic resource to serve demand, but that approach can conflict with state policies such as renewable portfolio standards or subsidies for nuclear power. The Federal Energy Regulatory Commission in May 2017 raised the same topic in a technical conference.

The upcoming PJM board meeting will focus on a redesign of the market through which PJM secures capacity three years in advance of when it is needed. The design change addresses concerns that nuclear subsidies like the zero emission credits, or ZECs, that were adopted in Illinois in 2016 could allow nuclear plants to underbid competing generation and force newer generation out of the market. Similar ZEC policies also are being considered in other PJM states.

The board's decision will provide some direction because PJM staff and members disagree on which solution best deals with ZECs and similar state policies. PJM staff favors a repricing solution that would split the existing annual single-stage capacity auction into two stages: the first would select supply, while the second would adjust the prices offered by certain subsidized resources to undo the market distortion that could occur if those resources offered at below their costs.

In 2017, a majority of stakeholders backed the extended minimum offer price rule solution, called "MOPR-ex," proposed by PJM's independent market monitor, Monitoring Analytics. That proposal is designed to prevent suppliers receiving out-of-market subsidies, including those from states, from bidding to sell power in the grid operator's capacity markets at below competitive price levels. Specifically, the proposal would require such resources to bid at or above a minimum floor price that represents their operating costs before subsidies are factored in.

What the board will consider

PJM President and CEO Andy Ott will recommend that the board implement the staff proposal after the May auction, which secures capacity for the 2021/2022 time period. PJM prefers that proposal because it better respects state programs, according to a letter from Ott dated Jan. 16 and addressed to the grid operator's members, states and stakeholders.

Though the MOPR-ex proposal might be the most "effective" means of preserving price integrity in the capacity markets, that approach would be "punitive" because it exempts state renewable policies but not those related to nuclear generation and therefore could exclude some subsidized generators from clearing, Ott said.

But Monitoring Analytics President Joseph Bowring previously denied that the approach is punitive, claiming that it ensures that states choosing to subsidize bear the costs of those subsidies instead spreading them across the market.

Bowring recommended that the board require PJM to implement the MOPR-ex proposal for the May auction. If it does not accept that recommendation, the board "can direct PJM to make a [Federal Power Act] Section 205 filing that includes both the PJM proposal and the MOPR-ex proposal and let FERC decide," Bowring told S&P Global.

Risks to the auction

Given the potential for changes in the capacity auction design, stakeholders' opinions on how they think this could affect the upcoming auctions or investment planning vary.

"Design change is coming — it's just a matter of when," NRG Energy Inc. spokesman David Gaier told S&P Global in a Feb. 2 email. "FERC certainly needs to weigh in soon and definitively, to address ZECs and other out-of-market subsidies and handouts to selected generators. However, because the current PJM proposal doesn't cleanly address the subsidy issue, we expect that there will be continued discussion at FERC on how its markets should evolve," Gaier added.

Steve Lieberman, director of PJM regulatory affairs at American Municipal Power Inc., said he is "doubtful" that nothing will get changed. Assuming a design change in 2019, Lieberman feels the 2018 auction clearing prices "are not going to be indicative most likely of future investment decisions." That will make deciding whether to invest in new generation or existing resources challenging for a developer or asset owner given that the market design could be different in the May 2019 auction, Lieberman added.

Manan Ahuja, senior director for Americas power analytics at S&P Global Platts, believes it is too early to tell the auction impacts. The broader concern will be whether developers rethink bidding new generation into the 2019 auction, which secures supply for the 2022/2023 period, Ahuja indicated.

"During last year's auction, it was quite close for some combined cycles in the sense that the clearing price was not high enough to incent a lot of new entry," Ahuja said. About 2,350 MW of new combined-cycle generation cleared in the 2017 auction, a substantial drop from the more than 5,000 MW that cleared in the prior year's auction, according to PJM.

S&P Global Platts and S&P Global Market Intelligence are owned by S&P Global Inc.