The forward capacity market has reduced overall costs of satisfying reliability requirements by fostering competition and has allowed cost-effective responses to the challenges presented by increasingly stringent environmental rules, Andrew Ott, executive vice president of markets with PJM Interconnection, told FERC.
In a statement filed before FERC’s Sept. 25 technical conference on centralized capacity markets in RTOs/ISOs, Ott said that while PJM’s capacity market design, the reliability pricing model (RPM), has been subject to continual review and improvement, PJM is better off having resolved the major design issues.
“The fact that since the inception of RPM we have been able to attract over 28,178 [MW] in new generation, over 14,370 MW of demand response resources and 1,113 MW of energy efficiency resources to replace plant retirements is a testament to the importance of the market designs … in achieving their intended results,” he said.
RPM has facilitated economically efficient tradeoffs among investment in environmental retrofits, retirement and replacement with lower-cost alternative supplies.
One critical concern PJM faced in 2006 was a series of impending retirements and the lack of a long-term forward auction to ensure that PJM had sufficient resources to meet its future reserve margin. In 2006, those retirements were driven by a series of local environmental rules imposed in New Jersey, Maryland and other states in the mid-Atlantic region, along with U.S. EPA enforcement actions.
Starting with the first auction in 2007, the capacity market provided an important forward price signal that helped ensure more informed decisions surrounding generator retirement. The key design elements – sloped demand curve, locational consideration and forward commitment – worked to provide critical transparent information that unit owners could use in making informed decisions on whether to retire or retrofit generation resources, Ott added.
Implementation of the Mercury and Air Toxics Standards (MATS) rule in PJM has proceeded more smoothly as a result of the forward certainty that RPM has brought. While more than 20,319 MW of mostly mid-merit coal units have retired, more than 47,000 MW of existing coal units committed their availability in the 2016 RPM base residual auction, representing a decision of the unit owners to retrofit their units, as necessary, based on the forward price signal that RPM provides.
Ott also said that PJM designed three key elements of RPM with a focus on attracting new investment, including the sloped demand curve, which was designed to address the historically “lumpy” nature of capacity investment and smooth out the “boom/bust” cycle of capacity pricing present with a vertical demand curve for capacity, which discourages long-term investments in increased capacity.
Since its start, the RPM has incented more than 14,370 MW of cleared demand response resources substituting for traditional generation resources to meet PJM’s capacity requirements. Additionally, Ott said, more than 1,112.6 MW of new energy efficiency resources cleared during the same period. The amount of demand response that has been bid into the market has steadily increased over time as well, from 2,000 MW during the 2007/2008 base residual auction to more than 14,000 MW in the 2015/2016 base residual auction.
However, while the amount of demand response has increased, almost all demand resources are specifying two-hour notice requirements and emergency-only status, resulting in more than 12,000 MW of demand response-based capacity resources having very similar operational characteristics.
PJM has experienced a large operational discontinuity because of the marked difference in operational comparability between generation and demand response given the notice requirements and emergency-only status of most of the demand response resources.
Because most of the demand response resources have demanded two-hour notice, the operators’ flexibility to deploy them quickly is reduced in real time when flexibility is the most valuable.
“PJM is working with our stakeholders and states on developing proposals to better integrate the capacity market design with these operational requirements,” Ott said.
ISO-NE capacity market achieves high-level goals, improvement still needed
Robert Ethier, vice president of market development with ISO New England (ISO-NE), said in his comments to FERC that to date, New England’s capacity market has achieved the high-level goals that capacity markets are designed to accomplish.
It has procured resources needed to meet the region’s capacity requirement, addressed the so-called ‘missing money’ problem and paid resources for providing capacity, and it has effectively replaced out-of-market reliability must-run (RMR) contracts with market-based compensation. The market has allowed entry of new resources and created a platform on which demand response can participate as a resource, Ethier added.
However, the capacity market does require improvement in three areas: product definition, resource performance and price formation.
Ethier also noted that it is difficult to declare the capacity market a success if a significant number of the resources that have been selected and compensated as capacity resources fail to perform as needed.
The region has experienced a NERC violation, nearly 200 reported instances of fuel unavailability and poor contingency response, with the ISO getting only about 60% of the requested megawatts in response to contingency reserve activations. Consequently, ISO-NE is concerned that the current market design will not succeed in assuring long-term reliability.
“Put simply, the performance of many resources has been poor and there have not been any consequences in the capacity market for such poor performance,” he said.
ISO-NE has been working closely with stakeholders to design a new performance incentives mechanism, or pay-for-performance, for the New England capacity market.
Moving forward, three elements rise to the top of the list of things that are key to the effective functioning of the market. Getting these three elements correct will drive an effective and efficient market that allows reliable system operations for the least cost in the long run: the capacity product must be properly defined; the price setting mechanism must work effectively to set a just and reasonable price for the product; and performance must be properly measured and the compensation for providing capacity must be completely linked to performance for every capacity resource under the same rules and measures.
Over the past year, ISO-NE has engaged in a stakeholder process that seeks to clearly define the capacity product and how its payment will be affected by performance, Ethier said.
ISO-NE plans to complete the stakeholder process on its pay-for-performance design in December and file tariff changes by year-end, allowing a FERC decision by May 2014, so that the proposed changes can be in place for the ninth capacity auction to be run in early 2015.
“[W]e plan to discuss a downward sloping demand curve and potential exemptions from the minimum price offer rules for certain state-sponsored renewable projects,” he said. “We expect these to be another potential set of market changes that will require significant stakeholder discussion before any submission to” FERC.
Under pay-for-performance, each resource’s FCM revenue will be contingent, in part, upon its actual performance during periods when aggregate performance does not allow ISO-NE to satisfy system reserve requirements.
The new design will result in transfers from underperforming to over-performing resources, providing strong incentives for each resource to perform as needed and for resources that can meet the system’s needs by exceeding their obligation to benefit by doing so.
The incentives will place performance risk on all FCM resources, and that risk will need to be priced in each resource’s bid in future capacity auctions.
Under today’s FCM rules, the capacity product lacks specificity and the performance obligations of capacity resources have various exceptions.
Under pay-for-performance, a capacity supplier’s FCM revenue will comprise two parts: a base payment, determined by the forward capacity auction result, and a performance payment, determined by a resource’s performance whenever scarcity conditions occur during the capacity commitment period.
Three fundamental principles underlying this approach include creating strong economic incentives for all capacity suppliers, without exception, to perform during scarcity conditions.
Among other things, Ethier noted that stakeholders have proposed a range of exemptions to the performance requirements under the pay-for-performance proposal, with the underlying rationale in each case being that it would be “unfair” to penalize a resource that did not perform for a particular reason.
ISO-NE has continued to reject such proposals, he said, adding, “Exemptions are inconsistent with the pay-for-performance construct under which you get paid for only what is delivered; deviating from this approach would bias the performance incentives away from desirable performance toward excepted performance.”
No recommendation in New York to consider mandatory forward procurement
David Patton, president of Potomac Economics, said in his Sept. 25 testimony that the New York ISO (NYISO) market design has been effective in facilitating investment and maintaining adequacy.
Buyer-side mitigation has been controversial, he said, and Potomac Economics has not recommended that NYISO consider mandatory forward procurement.
Stability in the design and operation of the capacity market is critical, he said, adding that investors must be able to project capacity revenue over the life of their resources. Also, instability raises investment risk that will cause investors to require higher prices to enter.
Market-based investment in wholesale electricity markets is ultimately facilitated by the markets’ economic signals, including energy and ancillary service net revenues during non-shortages; energy and ancillary service net revenues during shortages; and capacity market net revenues, Patton said.
Long-run equilibrium is achieved when the combination of those expected revenues cover entry costs of the marginal resource.
While theoretically sufficient, energy-only markets will generally not satisfy RTOs’ planning reserve needs. In other words, he added, there is “missing money.” Capacity markets exist primarily to provide the missing money and the only alternative to a capacity market is to artificially inflate shortage pricing, which raises a variety of concerns.
Missing money exists for three reasons: planning reserve requirements exceed levels that an energy-only market would provide, assuming the energy market prices shortages efficiently; the higher planning margins result in more supply, which reduces the frequency of shortages and associated shortage revenues; and real-time prices may not always fully reflect the value of energy because of the effects of the ISO’s reliability actions, such as committing peaking resources or other generating resources, curtailing load and curtailing exports.
An essential attribute to efficient capacity markets is the capacity demand curve, he added, noting that a vertical demand curve indicates that the last megawatt needed to meet the capacity requirement has extreme value and the first megawatt of surplus has no value. In reality, each megawatt of surplus capacity increases reliability, although those reliability increases diminish as the surplus grows.
A sloped demand curve reflects that additional capacity above the minimum does have reliability value, which decreases as the excess increases. The price would be determined by the marginal value of additional capacity as represented by the sloped demand curve, rather than by a supply offer.
A sloped demand curve provides more efficient prices that reflect the prevailing surplus; improves price stability, which should facilitate investment by reducing price risk; and reduces incentives to withhold capacity by raising the opportunity costs of withholding – foregone revenues – and decreasing its price effects, Patton added.
Rana Mukerji, senior vice president of market structures with NYISO, said in his Sept. 25 FERC comments that due to transmission constraints into certain localities, load serving entities serving those localities must procure a specified portion of their capacity requirements from resources electrically located within that locality.
New York has locational requirements for three transmission-constrained localities: New York City, Long Island and the Lower Hudson Valley.
He also noted that minimum installed capacity (ICAP) requirements are set before each capability year. Load serving entities can meet their capacity requirements by self-supply, bilateral transactions with suppliers, forward auctions and deficiency/spot market auctions.
NYISO’s planning process provides a backstop solution for preserving resource adequacy, according to Mukerji, who also noted that if market-based solutions are insufficient to meet reliability needs by the needed date, then:
- NYISO can “trigger” a regulated backstop solution.
- NYISO requests responsible transmission owners to seek state regulatory approval of a backstop solution.
- The state Public Service Commission (PSC) and other regulatory agencies proceed with their review and approval.
Mukerji also noted that the purpose of supplier-side mitigation is to prevent physical or economic withholding by suppliers who may have an incentive to raise prices, while the purpose of buyer-side mitigation is to prevent uneconomic entry from artificially suppressing capacity prices.
Discussing capacity markets at work, Mukerji noted that the state is “adding generation and transmission where it’s most needed,” such as more than 10,000 MW of new generation and more than 1,600 MW of new transmission. More than 5,000 MW of older generation is retiring and the state is fostering demand-side participation with about 1,500 MW of demand response.
Of the forward capacity market, Mukerji noted that it has the potential to increase costs out of a proportion to any improvements in reliability by being conservative in projecting forward requirements, and implementation would take too long to address near-term uncertainties related to retirements.
On current initiatives, Mukerji noted the implementation of a new locality – southeastern New York, or the Lower Hudson Valley and New York City – improvements in scarcity pricing and exemptions/enhancements to buyer-side mitigation rules upon stakeholder consideration. Such exemptions include clarifying market rules for mothballing and retirement of generators, he added.