PSEG weighs in on capacity market issues to be faced by FERC

The Federal Energy Regulatory Commission has a number of issues to deal with to clear the way for more effective centralized capacity markets, said Shahid Malik, President
 of PSEG Energy Resources & Trade LLC (ER&T).

PSEG was among several parties that on Sept. 9 filed written testimony with FERC ahead of a planned Sept. 25 technical conference on capacity market design.

ER&T is the marketing subsidiary of PSEG Power LLC, a wholesale generation company that owns and controls an approximately 13,000 MW deregulated portfolio of installed capacity in the PJM Interconnection, ISO-New England and New York ISO regions. Its portfolio utilizes a diverse mix of fuels: 45% gas, 27% nuclear, 18% coal and 9% oil.

“We have made substantial investments in our generating fleet in organized markets, including installing approximately $1.3 billion in back-end technology investments on our coal units, making them among the cleanest coal facilities in the country, and building several new peaking units in PJM,” Malik noted. “These investments would not have been made without the capacity market income streams that a forward capacity market provides. We also function as a load-serving entity, contracting with electric utility companies to satisfy their respective default service obligations to customers that have not chosen a third party supplier for electricity. Thus, PSEG’s decisions in the market are made through the dual lens of both a wholesale generator and an entity with contracted commitments to serve load.”

His comments are representative of the views of the PSEG Companies, which include PSEG Power as well as PSE&G, a franchised public utility in New Jersey. PSE&G relies on the capacity market to ensure adequate capacity to meet reliability needs and as a source of revenues for certain state-sponsored programs such as demand response and energy efficiency.

PSEG believes that the capacity markets, particularly PJM’s RPM, have generally served to ensure resource adequacy at reasonable cost and have been flexible enough to accommodate changing market conditions and policy goals, Malik said. “However, it is critical that capacity markets (and regulators overseeing them): (i) continue to ensure comparable treatment of all participating resources; and (ii) recognize the challenges facing merchant generation resources in competing with resources receiving subsidies, including ensuring that appropriate buyer-side mitigation measures are in place to reflect the existence of these subsidies,” he added.

“Missing money” a key issue in capacity markets

Capacity markets cannot be viewed in isolation. They are necessary because of the “missing money” problem associated with ISO/RTO mitigation in energy markets, and because the level of capacity procured for reliability is always above the amount required to serve just the energy needs of the system, Malik noted. As such, the industry has evolved to include as capacity resources less efficient and/or more costly units that rarely have the opportunity to recover energy market revenues or to set price, he added.

“An appropriate capacity market design needs to recognize the factors that influence market participants in making investments and should provide them with a reasonable opportunity to recover their investments and earn a competitive return,” Malik said. “The risks assumed by merchant generating companies need to be acknowledged by policy makers and we, the generators, must be willing to accept them. In terms of public policy objectives, such as the implementation of new environmental requirements, for example, this means that investors must have assurances that the implementation of those objectives will not interfere with price-setting market mechanisms. So, if capacity markets are well-designed and protected from interference, we can meet resource adequacy requirements in an efficient manner while still helping to meet state and federal policy goals.”

He noted that PSEG, through its subsidiary PSE&G, is investing over $700m in about 125 MW of solar generation to help meet New Jersey’s renewable portfolio standard. These MWs are grid-connected and bid into the capacity market, with revenues credited back to customers under state-approved programs. “We believe that clean, green energy should play a role in the generation resource mix in organized markets,” Malik wrote. “At the same time, the fundamental objectives of forward capacity markets must not be undermined in the process, and capacity market design must continue to ensure resource adequacy and system reliability at the lowest long-term cost.”

Capacity markets, such as PJM’s, have demonstrated that they already have the flexibility to accommodate policy goals for energy and capacity resources. For example, the RPM market design has facilitated the retirement of over 14,000 MW of coal units driven largely by the federal Mercury and Air Toxics Standards while still meeting reliability targets. Also, in PJM’s most recent base residual auction (BRA), there was an increase in wind and solar resources that cleared, with about 870 MW of wind resources clearing and around 90 MW of solar clearing. While the PJM capacity market design is not perfect, these are achievements for which PJM and its RPM should be commended, Malik said.

Malik criticizes market incentives in ISO-New England region

“Other ISOs, however, have not done as good a job in solving the ‘missing money’ problem,” Malik added. “We have deep reservations about the ISO-NE’s Forward Capacity Market (‘FCM’) construct. It has done a poor job of recognizing locational requirements or allowing units to submit offers reflecting their own risk-based costs of participation in the market. Because of these and other flaws, investments for new and existing generation have been chilled, resulting, for example, in the need for a special procurement by ISO-NE of ‘Winter Reliability’ capacity. ISO-NE’s plan to implement ‘performance’ based pricing in capacity markets is also poorly conceived and can be expected to result in the premature retirement of viable capacity resources while failing to incentivize new investment.”

Overall, capacity markets have been flexible in responding to changing market circumstances including growth of demand response, energy efficiency and renewables. Yet, specific improvements are needed. Malik said these improvements include:

  • Avoiding “managing the market.” In PJM, for example, over the last year there have seen regular instances of “second-guessing” by the RTO of the economic Day-Ahead market dispatch. As a result, units that PJM deems to be needed in the Real-Time reliability dispatch are added to the Day-Ahead dispatch even though they are not economic, which depresses Day-Ahead prices. “While PJM’s intentions may have been benign – such as securing uneconomic resources needed for reactive power requirements – the impacts of this course of action reduce the energy market contribution to below competitive levels,” Malik wrote.
  • Ensuring capacity imports are reliable. The market has seen considerable increases in capacity imports into PJM from neighboring control areas. In the last PJM BRA, imports of capacity from outside of PJM nearly doubled from last year’s auction, totaling about 7,500 MW. These capacity imports do not have a “must-offer” capacity market requirement like inside PJM capacity resources. This may ultimately deter investment in PJM and place even more stress on the capacity market to support new entry and to preserve the economic viability of existing resources needed for reliability.
  • Eliminating the 2.5% short-term resource procurement target in RPM. This rule, which removes 2.5% of the reliability requirement for RPM from the demand curve, has price suppressive effects and will discourage new entry into the market.

“Beyond these specific recommendations, we believe that two fundamental principles need to be followed for the capacity market construct to remain viable in the face of changing public policy choices,” Malik said. “First, because capacity is mainly a reliability product that is based upon having sufficient resources to meet future requirements, the contribution to reliability of capacity from different technology types has to be comparable. ‘Comparable’ does not necessarily mean identical but it does mean that different resource types have to be sufficiently similar to traditional central station generation resources to meet prevailing reliability standards. In the case of some type of non-traditional resources that have been favored by policy makers, such as wind and solar, this comparability can be largely achieved by recognizing the intermittency of the energy source and adjusting the capacity value based on performance of like resources.”

Second, the integrity of capacity markets is directly threatened by the impact of subsidized resources entering the market even if it appears that valid policy goals might be achieved through these subsidies. “Market participants investing in merchant generation resources have difficulty competing with resources receiving discriminatory subsidies, such as state-mandated non-bypassable surcharges or guaranteed investment recovery rate designs for regulated utilities,” Malik wrote. “Government actions such as these effectively pick and choose winners, leaving those who rely on market outcomes as the losers.”

About Barry Cassell 20414 Articles
Barry Cassell is Chief Analyst for GenerationHub covering coal and emission controls issues, projects and policy. He has covered the coal and power generation industry for more than 24 years, beginning in November 2011 at GenerationHub and prior to that as editor of SNL Energy’s Coal Report. He was formerly with Coal Outlook for 15 years as the publication’s editor and contributing writer, and prior to that he was editor of Coal & Synfuels Technology and associate editor of The Energy Report. He has a bachelor’s degree from Central Michigan University.