June 11, 2018

“Pay-for-performance” capacity market incentives implemented as of June 1, 2018

“Pay-for-performance” (PFP)—a cornerstone of ISO New England’s ongoing, multi-faceted effort to address trends that are challenging power system reliability—became effective on June 1, 2018. PFP is part of New England’s Forward Capacity Market (FCM) design, which acquires obligations from resources needed to meet demand three years into the future. The new PFP rules provide enhanced incentives, in a carrot-and-stick approach, for resource owners to ensure their resources are ready and able to meet their obligations to provide energy and reserves or reduce demand during times of stress on the regional power system. Now, resources with a capacity obligation can be penalized $2,000 per megawatt-hour (MWh) for failing to meet their obligation during energy shortfalls, while resources that over-perform relative to their obligation (including resources with no obligation) can receive $2,000/MWh of additional revenue. This performance payment rate is scheduled to increase to $5,455/MWh over the next six years.

These incentives were developed to help address a serious problem: rising generator outage rates, which resulted in many of the region’s power plants being unavailable (i.e., failure to meet their obligation) at critical times of power supply shortages. PFP significantly improves the FCM design, and there have been some signs of progress since its inception, but time will be needed to assess whether PFP, especially its phased-in payment plan, will be sufficient to address the region’s growing fuel-security risks.

Factors driving poor resource performance

The rising number of outages and poor response rate of the region’s power plant fleet could be traced to several factors:

Not having firm contracts for fuel delivery
Not staffing power plants or not keeping up with plant maintenance
Some natural-gas-fired generators with dual-fuel capability (the ability to burn oil stored onsite if natural gas unavailable) no longer maintaining that capability
Natural-gas-fired generators having trouble getting natural gas during cold weather, when the fuel is in high demand for both heating and power generation
Oil- and coal-fired power plants not stockpiling enough coal or oil to operate for extended periods because their fuel is expensive and they were rarely dispatched
Older oil- and coal-fired power plants that rarely operated often having mechanical problems when they tried to start up

Weak incentives

The new rules are designed to correct flaws in the original FCM design, which was developed during a 2006 settlement proceeding among market participants, state regulators, and the ISO. In the original design, resources received monthly payments through FCM in exchange for their obligation to generate electricity or reduce demand when dispatched during a shortage event. The original penalties for non-performance during a shortage event were small, and the region’s definition of a shortage event—that is, a period of time when the supply of electricity is insufficient to meet consumer demand plus reserve requirements—was so restrictive that there were just two declared shortage events in 12 years. In other words, resource owners received their monthly capacity payments whether they were capable of meeting their capacity obligation or not.

The weak link between capacity payments and performance provided little incentive for owners to invest in their resources to ensure that they were capable of providing energy and reserves when needed. The lagging investment in existing resources resulted in challenging times for ISO New England system operators striving to maintain power system reliability, particularly during extremely cold weather. The biggest challenge is the region’s increasing use of natural gas for power generation, increasing demand for natural gas for heating, and a lack of expansion of the region’s natural gas pipeline system to meet that growing demand. The result has been that during very cold weather, when demand for natural gas for heating is high, some natural-gas-fired generators could not get fuel.

The ISO launched the Strategic Planning Initiative in 2010 to address several interconnected challenges facing the regional power system, including this issue. The ISO first proposed performance incentives in a 2012 white paper that described the problem and proposed a solution: meaningful incentives for resources to make sure they would have the fuel, perform the maintenance, and assign the staff they needed to operate as promised during times of system stress. Over the next 14 months, the ISO led an intensive stakeholder process to discuss and refine the proposed incentives.

The ISO filed its PFP proposal with the Federal Energy Regulatory Commission (FERC) in January 2014 and FERC ruled in May 2014 that the problems were real and well-documented, that the PFP design was sound, and that addressing these concerns was essential. So with FERC’s approval, the ninth Forward Capacity Market auction, held in February 2015 for the 2018-2019 capacity commitment period, was the first auction that incorporated PFP rules, and 2018-2019 was the first year during which capacity resources could be subject to PFP requirements.

Goals, principles, and structure of PFP

The goal of performance incentives is to improve power system reliability by providing appropriate pricing—developed through competitive markets rather than administratively imposed prices—that will adequately compensate resources that meet their capacity supply obligations. The incentive program is designed to attract and retain the resources needed to meet demand, and encourage resource owners to make the arrangements necessary to ensure their resources will be able to respond as promised.

Stronger incentives will lead over time to a shift in the resource mix that directly improves system reliability at the lowest cost. Older resources that can’t reliably perform, and tend to be more expensive, are expected to choose retirement rather than be subject to increasing non-performance charges, making room instead for more efficient, less costly, and more reliable resources.

Pay-for-performance implements a two-settlement system of credits and charges that is similar to the structure of the ISO’s energy markets. It’s a system that is also used in many other forward contracts in other industries. Each supplier with a capacity supply obligation in the Forward Capacity Auction will receive its monthly capacity payment, but it is then subject to a second settlement based on its actual performance during scarcity conditions. Under this design, resources that perform poorly cover their forward obligations by paying the resources that had to overperform to cover for them.

Pay-for-performance is based on several important principles:

Capacity payments should be linked to how well resources meet their capacity supply obligation during shortage events
Using a two-settlement system, ratepayers will not be liable for the costs of underperforming resources
PFP requirements apply equally to all resource types, regardless of technology or fuel
There are no exceptions or exemptions from the requirement for resources with a capacity supply obligation to provide energy or a demand reduction during shortage events

PFP incentives will be fully implemented in 2024

Pay-for-performance has been a long time coming, in part because the forward nature of the FCM resulted in a three-year implementation delay, and also because the incentive payments are being phased in. While the current capacity period is the first with pay-for-performance rules in effect, the full effect of PFP will not be seen until June 1, 2024. That’s because under the current rules, the charges are being phased in over the next six years:

June 1, 2018, through May 31, 2021: $2,000 per megawatt-hour (MWh)
June 1, 2021, through May 31, 2024: $3,500/MWh
June 1, 2024, and thereafter: $5,455/MWh

“As pay-for-performance is phased in over the next several years, the data will determine how well it achieves the reliability benefits we sought when the design was introduced five years ago,” said Matthew White, the ISO’s chief economist. “But we have seen some promising signs since PFP was approved. For example, a combination of PFP and other incentive programs has brought more dual-fuel capability to the region than we had in 2013, and the response rate of the fast-start fleet has improved steadily. We’ve also heard, anecdotally, that many large power plants have accelerated major maintenance in order to be ready to meet their obligations.” About 2,500 megawatts of dual-fuel capability has been added or proposed since FERC approved PFP in 2014.

“These are all encouraging signs, but we won’t be able to fully evaluate it until we see how resources respond and the system operates through stressed, shortage event, conditions,” White said.

PFP and the evolving power system

At the same time, the power system has changed dramatically in the last five years. Retirements of power plants that use fuels other than natural gas have accelerated. The cost of adding dual-fuel capability has risen higher than expected, and resource owners have not added not as much new dual-fuel capability as initially hoped for. Some states are tightening their restrictions on power plant emissions, which means dual-fuel power plants will face more stringent limits on how much oil they can burn. Those limits will likely deter investment in more dual-fuel capability.

Contracting for liquefied natural gas (LNG) is another way for natural-gas-fired generators to ensure they can get fuel in winter without depending on natural gas from the region’s constrained pipeline infrastructure. LNG contracts are significantly more costly than adding dual-fuel capability, so at the time the PFP incentives were developed, the ISO expected power plants would be unlikely to contract for LNG. And so far, few generators have done that, but the ISO is watching to see if seasonal LNG contracting increases as the performance payment rates increase.

Given the real challenges the ISO’s system operators have had to work through during recent cold winters and the region’s increasing fuel security risk, there is some concern that the phase-in of incentive rates may be too protracted. Accelerating the payment rate or strengthening the rewards and risks are possible approaches to addressing the region’s fuel-security problems.

Further reading