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Maryland Consumer Advocate, State Agencies Urge Long-Term Contracts Under SOS to Mitigate "Harm" from RPM

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October 6, 2010

Arguing that PJM's Reliability Pricing Model is causing "harm" to Maryland ratepayers, several Maryland consumer advocates and state agencies have urged the PSC to implement a managed portfolio process for ensuring adequate electric supplies for ratepayers, with provisions for long-term contracting for new capacity, in comments in the PSC's investigation into RPM (PC 22).

"The design of the RPM market has forced consumers to purchase capacity well in excess of the amounts need [sic] to meet reliability requirements at prices that far exceed the value of that capacity.  There is little indication that consumers have gotten much of value from those excessive payments," the Office of People's Counsel said.

"RPM clearing prices have failed to spur development of new capacity in Maryland.  Instead, implementation of the RPM market has resulted for the most part in a massive transfer of wealth from consumers to owners of existing capacity resources.  Unfortunately, neither PJM nor FERC has been particularly receptive to proposals from consumer advocates, other representatives of capacity buyers, or state regulatory commissions for changes to the RPM market design that might mitigate the harm to consumers," OPC added.

Accordingly, OPC said that, "the Commission should consider requiring Maryland's distribution utilities to either invest in or enter into long-term contracts for transmission, generation, or demand-side resources when it is economic to do so."

The University System of Maryland also favored changes to the structure of SOS to mitigate the price impacts of RPM.  "The most effective mechanism for the Commission to adopt to encourage the development of supply in Maryland is a managed portfolio of differing contract lengths," USM argued.

"With the enactment of deregulation of electricity supply in Maryland, ratepayers have lost most protection from market prices ... The only way to limit [fuel-driven price] increases is to create a supply portfolio that is not 100% tied to current fuel prices.  This can be accomplished through the purchase of renewable energy and/or fixed price contracts from non-renewable projects," USM said.

"The Commission should recognize that for the foreseeable future there will be reliance by retail customers on the utilities' standard offer service.  Given that realization, it should be the responsibility of the State and the Commission to stabilize the energy rates absent returning to full regulation.  Stabilization of rates may mean that some ratepayers are paying more than the current spot market price for energy, capacity and RECs (to meet Renewable Portfolio Standards ('RPS')), but at other times they may be paying less," USM added

USM suggested that initially the state could purchase 5% of supply from new projects each year for the next five years.  After five years, USM said that there would be long-term contracts for over 1,000 MW of new generation, based on conservative estimates of load still served by the utilities.

"There has to be some quantity of supply to serve SOS that is purchased long term (over ten years) resulting in price stabilization to ratepayers.  USM would advocate that at least 25% of SOS load be purchased long term and diversified in regards to technologies, location, project owners, and pricing," USM added.

"It is likely that a twenty year power purchase agreement for any type of generation will result in capacity pricing lower than the realized PJM RPM pricing over the same term," USM said.

The Maryland Energy Administration likewise urged the Commission to, "move expeditiously on the long-pending proceedings which provide mechanisms for contracting for new in-State resources by the utilities, as allowed by current law."

A managed portfolio featuring expansion of in-state generation, and providing long-term supply resources, "will help achieve the State's policy goals of affordable, reliable, and clean energy, and also serve to enhance price stability," MEA said.

MEA also said that the Commission must examine, "a possible exit from PJM on its own or in conjunction with other similarly situated states."

The American Public Power Association added that, "a much better alternative to centralized capacity markets would be for states to implement competitive power supply procurement processes to obtain a diversified resource portfolio for regulated LSEs serving loads in the PJM region."

"A significant portion of the power supplies would be procured under longer-term contracts of varied length and/or owned-generation arrangements ... Such a competitive procurement process would do a much better job of anchoring needed new generation and supply-side resources than continuation of RPM," APPA said.

"The notion that capacity buyers need not do anything to accomplish resource adequacy because merchant power plants would be built where and when needed has been proven incorrect.  Therefore, states, load-serving entities and large customers should be more proactive in anticipating and arranging for future resource adequacy," said James Wilson, founder of Wilson Energy Economics and an affiliate of LECG, on behalf of the Southern Maryland Electric Cooperative.

CPV Maryland said that, "Maryland is best served by addressing these issues directly at the PSC.  The PSC has and should exercise its authority to address the inherent barriers to new generation development under the current RPM structure by awarding long-term contracts for the construction of new generating capacity in the State of Maryland."

Specific Criticisms of RPM
OPC said that, "[t]he major innovations of the RPM market - the sloped demand curve and locational price clearing - were supposed to reduce capacity costs to buyers and provide stable locational price signals to developers of new capacity.  Results from the last seven RPM auctions have shown the opposite to be true. Payments to capacity owners in the 2013-14 auctions alone were approximately $5 billion more than they would have been if the auction had been cleared without the demand curve or locational pricing."

OPC said that RPM over-procures capacity, noting that for the 2013/14 delivery year, the auction procured a reserve margin of 20.2%, compared with the Installed Reserve Margin of 15.3%.  OPC cited over-procurements of similar magnitude in prior auctions.

In presenting an analysis on behalf of SMECO, Wilson said that, "[t]he notion that by holding RPM's auctions three years in advance they would determine the winners and losers among competing offers to build new power plants should be dropped."

"It was never based on any sound economic or business logic, and it is now disproven by RPM results.  RPM's auctions have not played a role in influencing these long-term decisions.  The expectation of future capacity payments will, of course, be a factor in decisions to undertake major investments.  But the outcome of one RPM auction will not be decisive.  Nor would it be helpful to offer multi-year price commitments through RPM, or otherwise attempt to stretch RPM to do what it is unable to do," Wilson said.

CPV Maryland contended that, "[t]he simple and uncontestable fact is that RPM's three-year new entry pricing window plainly is insufficient to finance the construction of new generation resources."

"And it is just as obvious, particularly in this uncertain regulatory and economic environment, that new ... generation plants simply will not be built without long-term power purchase agreements," CPV said.

CPV cited statements from lenders Natixis; Bank of Tokyo-Mitsubishi UFJ, Ltd.; Societe Generale; Union Bank; and Credit Agricole indicating that three and even five year commitments are insufficient to support new development.

Wilson said that RPM has not performed as expected and intended because, "industry conditions have evolved away from those for which RPM was designed based on conditions at the time (in 2003-2005)."

"At that time, nearly all new capacity was gas-fired, and RPM's design reflects expectations that new plants would be built under 'merchant' circumstances, relying exclusively on revenues from PJM's spot energy, ancillary services, and capacity markets. Gas-fired plants require three years to build, and at that time load growth had been and was expected to remain steady," Wilson said.

"The notion that new power plants could be built under pure merchant circumstances has long been recognized as unrealistic and it is now understood that financing major investments still requires a long-term source of revenue," Wilson stated.

Furthermore, Wilson said that, "[t]he notion that new power plants would be offered into the BRAs [Base Residual Auctions] at prices near Net CONE [Cost of New Entry] never made any sense.  Decisions to undertake major investments in resources with useful lives of 20 years or longer are based on long-term expectations over the life of the project.  Offering the capacity at Net CONE would presumably mean that the sponsor would proceed with construction if and only if the RPM clearing price was above Net CONE.  However, the sponsor of a long-lived project will not rationally allow an auction that sets a payment for a single year to determine his decision whether or not to proceed with construction; that does not make sense for a merchant plant or one with a longer-term source of revenue.  These major decisions are taken outside of RPM, based on long-term expectations of energy, ancillary services and capacity prices and available incentives and revenue guarantees."

Wilson noted that for the 2013/14 BRA, all 1,670.4 MW of new generation cleared in the Rest of RTO region at a price of $27.73/MW-day.  "This suggests that new capacity is offered at very low prices into the BRAs," Wilson noted, rather than a price near Net CONE.

"Other regions in North America are achieving resource adequacy without implementing a mechanism such as RPM.  At present, only three areas of the country have mandatory centralized capacity markets: PJM, ISO New England, and New York ISO.  These three mechanisms are all based on the same basic design that was proposed in a 2003 report that the three RTOs jointly funded," Wilson noted.

"Other regions in the U.S. and Canada are employing a variety of other approaches to resource adequacy, such as: energy-only markets (ERCOT, Alberta, Ontario); reserve obligations without a centralized capacity market (SPP, California ISO); and a voluntary capacity market (MISO).  However, all of these approaches have met or exceeded the objective of adequate resources.  According to NERC's 2009 Long-Term Reliability Assessment report, all regions of North America have adequate deliverable capacity resources (including potential resources reduced by a confidence factor) at least through 2018, with the exception of only the Carolinas and Quebec, where resources are adequate at least through 2015," Wilson added.

Wilson also criticized the three-year-forward obligations since they are determined based on peak load forecasts prepared over 40 months in advance of the summer peak period, which can be highly inaccurate.  "Excessive peak load forecasts have repeatedly resulted in acquisition of a large amount of excess capacity through RPM at excessive prices and cost," Wilson said.

Wilson cited the "seemingly paradoxical result" under RPM that in the Rest of RTO region, despite much lower RPM clearing prices, relatively more incremental capacity has been appearing than in the MAAC or smaller PJM zones where prices have been much higher.

Furthermore, Wilson raised concerns about withholding under RPM, noting that in the First Incremental Auction for the 2012/2013 delivery year, over 800 MW of capacity in Eastern MAAC that had failed to clear in the BRA, of which some had been offered at over $200/MW-day, cleared at a price of $153.67/MW-day.

"Why would a seller accept $153.67/MW-day in the incremental auction, if $200/MW-day was not enough in the BRA?  One explanation is that offering this capacity at a more competitive price in the BRA would have lowered the clearing price in the BRA that is earned by the rest of a capacity seller's portfolio," Wilson said.

Wilson suggested that the RPM auctions should be repurposed to more clearly and effectively focus on coordinating the various short-term decisions to provide incremental capacity, and de-emphasizing the "failed concept that RPM's auctions would coordinate long-term investments such as major new power plants."

"RPM serves the role of a capacity spot market, offering one-year commitments for the coming delivery year, and coordinating incremental decisions to provide or not provide capacity to the PJM market and zones for that year," Wilson said.

   
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