Capacity Market Costs Drive Utility to Want to Leave PJM, Join Midwest ISO

Michael Giberson

Duquesne Light has announced it wants to drop out of PJM and join the neighboring Midwest ISO, citing the high costs emerging from PJM’s capacity market as their motivation. The capacity market is called the “RPM” market after the “reliability pricing model” which serves as the underlying pricing mechanism. Duquesne has filed a request with FERC seeking a Commission order directing PJM to exclude the utility from the next running of the RPM auction, scheduled to begin next week. The Energy Legal Blog presents a few more details, and notes a few other cases in which utilities are eying the exits.

The Pittsburgh Tribune-Review made brief mention of the request in a column of energy-related notes:

The Downtown-based utility joined PJM in 2005, but said the organization’s price changes since then would increase its costs in coming years. “We don’t feel that is what is best for customers,” spokesman Joe Vallarian said. … The company said it may join another grid operator based in Indiana; it wants to avoid costs related to the PJM auctions.

The Electric Power Supply Association (EPSA) responded in the filing at FERC requesting the agency to deny Duquesne’s request. In a news release, EPSA stated:

“FERC should deny Duquesne’s complaint on the grounds that Duquesne remains a signatory to PJM’s reliability agreement and, contrary to what Duquesne has claimed, there is no credible information that the utility will not be in PJM in 2009,” said John E. Shelk, President and CEO of EPSA.

EPSA is the trade association representing the “competitive power supply industry,” i.e. non-utility generators, and its members will be net recipients of payments from the PJM’s RPM markets. Duquesne Light, on the other hand, as predominantly a wires-and-retail power services company will be net payers into the RPM markets.


2 thoughts on “Capacity Market Costs Drive Utility to Want to Leave PJM, Join Midwest ISO

  1. It will be interesting to see the prices resulting from October’s auction will actually stimulate plans for new generation, particularly in the eastern half of PJM, or if generators will wait to see the results of the Jan. auction.

    Thinking about high capacity prices in an environment of increasing regulatory risk (driven by high commodity prices, higher capital costs, and higher infrastructure costs, it’s not difficult to imagine state regulators in PJM East approving utility self-build (the process has started in MD). I don’t think VA will be the last state to re-regulate.

  2. RPM costs are only one piece–a small one, I would argue–in the puzzle over DQE’s exit from PJM. The RPM angle caught the headlines because it was DQE’s emergency filing at FERC to be exempted from the Oct RPM BRA that made public the months-long negotiations with PJM over DQE’s exit.

    First and foremost is the allocation of EHV transmission costs, which PJM does pro rata to load, rather than on a more rational allocation to those who benefit. PJM has authorized a lot of expensive transmission to move power from west (where DQE sits) to east. The effect is a double-whammy for DQE: DQE pays to build the lines to increase its power costs. This transmission allocation issue also underlies Maine’s saber-rattling about leaving ISO-NE.

    Second, DQE is squeezed by a retail rate cap, so it is DQE shareholders, not ratepayers, who will eat these costs. Convenient that DQE just got bought by some Aussies, neh?

    FERC has been repeatedly warned (by Duke, among others) that allowing substantially different rules in PJM and MISO will lead to market disruptions. This physical breakup is one consequence that they didn’t predict, however, which in hindsight was fairly obvious.

    Should we panic that PJM is falling apart at the edges? Maybe a little. If DQE manages to escape relatively unscathed, look for Dayton to pull out, and maybe AEP, who has little love for PJM markets. If AEP falls, ComEd will have little choice but to leave, and VA lawmakers(who have a piece of AEP in western VA) may decide that PJM isn’t all they had hoped it would be. So maybe the borders of PJM retreat back to the pre-2005 MAAC+APS world.

    Such a breakup would not be good for electricity markets. Not everyone would end up in an RTO, but would try to free-ride on the benefits of the neighboring markets (like LSE is doing today). It’s a shame that Betsy Moler didn’t push through the mandatory RTO membership when she was chairman.

    On a side note, I agree with Mike that we’re likely to see more states authorize rate-base builds. That won’t mean that RPM has failed. RPM was designed to work as intended even if _every_ LSE (including IOUs) self-procures. By creating a robust set of forward and spot markets, in fact, RPM can support such long-term bilateral contracting by providing transparent pricing and market liquidity for re-trading. RPM will also provide an important market price that allows these utilties to assess whether self-build is cheaper than market, and to allow regulators to hold utilities accountable for their decisions. Even though RPM is not a “market” as classically defined, it was intended to be–and, I believe, will become–an important adjunct to the operation of power markets and long-run investment.

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