The New England Power Pool Markets Committee voted Wednesday to amend Market Rule 1 to limit the retention of resources needed for fuel security to a two-year maximum.

One abstention from the Transmission sector was recorded.

ISO-NE’s director of NEPOOL relations, Allison DiGrande, delivered a memo arguing that “the change will better align the fuel-security retention rules with the ISO’s goal for reliability concerns to be addressed through competitive solutions, as it will appropriately limit the time and scope of resources retained for fuel security.”

The RTO requested that the change become effective prior to the issuance of the Order 1000 request for proposals targeted for this December. In a presentation in August, the RTO said the change “will help prevent uncertainty … in the development of transmission to meet the Greater Boston Needs Assessment.”

Price-responsive Demand Clean-up Changes

The MC voted to approve clean-up revisions to Market Rule 1 that were identified during the price-responsive demand (PRD) implementation process. One opposition from the Generation sector was recorded.

The RTO’s director of demand resource strategy, Henry Yoshimura, presented two sets of Tariff changes that:

• Clarify the energy market offer requirements of demand response resources that participate in the Forward Capacity Market; and
• Eliminate the requirement that ISO-NE publish the quantity of demand capacity resources at the end-of-round price for each capacity zone as the FCA is being conducted.

Yoshimura said the energy market offer change was amended slightly from the version presented on Sept. 4 to address a concern that the original proposal could be interpreted to require a market participant with a capacity supply obligation to submit demand reduction offers into the energy market that include avoided transmission and distribution losses for the non-net supply portion of the offer.

Yoshimura, who said that such a requirement would conflict with another section of the Tariff, said the proposal was amended to avoid any misinterpretation.

Order 841 Manual Changes

The MC also voted to recommend Participants Committee support for implementation of manual provisions to encourage electric storage participation in the New England wholesale markets.

One opposition vote from the Generation sector and one abstention from the Supplier sector were recorded.

An RTO development analyst, Catherine McDonough, presented the proposed manual revisions, which also include changes to address a stakeholder concern with how the maximum discharge limit of an electric storage facility is set when it has less than one hour of available energy.

The changes to manuals M-11, M-20, M-35, M-REG, M-RPA and M-36 also include clean-up changes to improve clarity and consistency.

The manual changes pertaining to enhanced storage participation would become effective upon PC approval; the committee’s next meeting is Oct. 4. Changes related to FERC Order 841 compliance would take effect in December 2019 while those that address concerns about discharge limit would be effective in two phases in December 2019 and March 2020.

Assessing EE Resource Performance

The MC discussed the Demand Resources Working Group (DRWG) report issued in July on the measurement and verification of off-peak hour performance of energy efficiency resources. The RTO currently calculates only on-peak hour performance for EERs, passive, non-dispatchable measures.

Yoshimura presented an analysis of five options the working group considered, including calculating a single average hourly demand reduction value for all off-peak hours. Another proposal would shape on-peak savings estimates to all hours based on the relationship between estimated performance under on-peak system conditions (reference load) and all other performance hour system conditions.

Shaping Option A, which would estimate hourly EER performance as a function of established on-peak EER savings and system load levels, received the most support of the options discussed, Yoshimura said, noting that savings and load levels are generally correlated. He said Shaping Option A also was identified as the option requiring the least time and expense to implement.

The other options required obtaining data not previously captured, additional analysis that would increase the cost and require more time to implement or might “not meet current precision and confidence interval requirements,” he said.

Yoshimura said the working group’s report did not represent a consensus behind Shaping Option A, however, noting concerns of some that it could overstate performance.

More Analysis on ESI Impacts

Todd Schatzki of Analysis Group, with ISO-NE economist Christopher Geissler, presented an evaluation of the impacts of implementing Energy Security Improvements (ESI) to increase generator incentives to secure energy inventory.

The analysis compares the cost and benefits to individual resources that take steps to improve fuel security under various scenarios.

The analysis evaluated inventory decisions by oil-fired resources and forward LNG contracts by gas-only resources. Benefits were identified as the “direct incentives” (revenues) created by ESI through forecast energy requirement (FER) payments and day-ahead energy options. Costs included contractual costs and holding costs for maintaining additional inventory. Analysis Group concluded that ESI would increase incentives for procuring incremental fuel compared to current market rules.

Under the “frequent stressed conditions” scenario, it found that increased revenues from FER payments and day-ahead energy options would exceed additional fuel holding costs for all categories of oil-fired resources. The results were similar under the “extended stress” case.

Under the “infrequent stressed conditions” case, all plants except those with large tanks would have increased incentives for energy inventory.

For oil-fired generators, “ESI unambiguously increases incentives for energy inventory,” Schatzki’s presentation said.

Schatzki also said ESI will provide incentives for gas-only plants to enter into forward LNG contracts compared with the incentives under current market rules. “FER payments increase the value of holding energy inventory by over $2,000/MW in two of three cases,” he said.

— Michael Kuser