RASC: BPM-011 RAN Seasonal Implementation Draft Language (RASC-2019-2, 2020-2, 2020-3) (20221012)

CPower Comments to MISO’s October 12, 2022 RASC Feedback Request

October 19, 2022

During the October 12, 2022 RASC meeting, MISO presented draft redline edits to BPM-011 to reflect the Seasonal Accredited Capacity market design approved by the Federal Energy Regulatory Commission on August 31, 2022. Enerwise Global Technologies, LLC d/b/a CPower (“CPower”) appreciates the opportunity to provide feedback to MISO on the draft redlines and thanks MISO staff for their review and consideration. Should you have any questions, please do not hesitate to contact Peter Dotson-Westphalen.

There are two sections of the draft BPM language regarding which we offer feedback below.

1. Section 6.5.2 – DR Performance

In Section 6.5.2 – DR Performance, there is a new sentence that has been added that states, “DRs that registered with a firm service level Measurement and Verification methodology must still show a [l]oad reduction to their firm service level in response to scheduling instructions or be subjected to the penalties described above.” This language was included in the draft BPM-011 version posted for review along with the materials for the RASC meeting held on August 24, 2022. CPower had provided feedback through the MISO Help Center and with MISO staff raising concerns with the language as drafted. The language, which implies that there must be a load reduction when an LMR is dispatched – even if the LMR is already operating at or below its firm service level – or the MP would be subjected to penalties. This language also appears to conflict with (existing) language in Section 4.2.7.2 – LMR Performance Obligations where it states that, “[a]…DR…must respond with an amount greater than or equal to the target level of load reduction or reduce demand to at or below the registered firm service level,” and later in the same section, “[a] penalty will not be assessed for any portion of the target level of Load reduction for a DR…which had already been accomplished for other reasons (i.e. for economic considerations….or local reliability concerns) and properly reflected in the hourly availability in the DSRI…”

In following email correspondence with MISO staff, we were told that this proposed language in Section 6.5.2 present in the August 24^th version was just a placeholder and that this language would not be included in the final BPM release. We understand if this language was not removed between the drafts posted for the August 24^th and October 12^th RASC meetings and was just an oversight. However, if MISO opts to retain this language in the final BPM updates, CPower remains concerned about the implications this language may have on all DR LMRs that MPs choose to register with a firm service level and would recommend MISO staff review supporting documentation provided by Ken Schissler from CPower via email and in the Help Center.

1. Appendix T – ICAP Deferral Notice

LMRs are not listed as a Planning Resource type that a Market Participant (“MP”) can select if it has a LMR for which it needs to submit an ICAP Deferral Notice. We recommend that “Load Modifying Resource (LMR)” be added to the list.

Respectfully,

Peter Dotson-Westphalen

Sr. Director, Market Development & Regulatory Affairs

CPower

Peter.D.Westphalen@CPowerEnergyManagement.com

781-214-7523

Xcel Energy appreciates the opportunity to provide feedback on additional revisions to BPM-011 .  Our revisions focus on three areas:

• Statements that are misaligned with the Tariff (as identified in the comments)
• Remaining clean-up for ICAP Deferral on a seasonal basis and Mid-Year Capacity Replacement to ensure that all Resources (including DIR and LMR) are eligible
• Revisions to datasets used for ELCC calculations, as described at the October RASC.

 We have sent our red-lined version of the BPM-011 document provided at the October RASC to Stakeholder Relations and would be happy to address any questions.

WPPI provides the bulk of its comments and suggested edits in a separately submitted red-line document.  In that review we have focused on Appendix Y.

In addition, we suggest that the BPM consider dropping the "AAOC Hours" term, and replace it with "Annual RA Hours," which is used in Schedule 53.  Adoption of the terms Seasonal RA Hours and Annual RA Hours may facilitate clarification of process descriptions in the BPM.

How should MISO account for Firm Service Level (FSL) and Emergency Demand Response (EDR)?

4. Add additional fields to report EDR offers

Should MISO still consider transmission losses and Planning Reserve Margin (PRM) add back for LMRs?

1. Status quo

Transmission Losses:

LMR's ZRC value should continue to get grossed up for transmission losses because they are offsetting the need for traditional generation that is connected to the transmission system. In order for generation to serve load, that generator's MW power at the point of interconnection needs to travel through transmission network losses to serve network load. LMR's provide that equivalent service locally without carrying electrons through lossy transmission lines, therefore their the LMR's MW reduction service is equivalent to the generators MW power + Transmission Losses.

To reiterate, consider a 100 MW Generator that delivers electricity through a 1 MW transmission loss, so it only delivers 99 MW of load at the point of consumption. Alternatively, if that load was able to be curtailed by a 99MW LMR, it provides the equivalent capacity value to the Bulk Electric System as a 100 MW generator would have otherwise provided.

Planning Reserve Margin (PRM):

LMR's ZRC value should continue to get grossed up for PRM because the load reduction measures help to lower the additional risk margin of a MP's load requirements + risk margin (aka PRM).

If an un-registered 100 MW load management measure "LMM" is dispatched over peak conditions and contributes to the reduction of an LSE's coincident peak forecast requirements and PRMR, the load reductions value is providing 100 MW + PRM% value to the overall need to procure PRMR. Suppose PRM% = 8%, then an unregistered 100MW load management measure provides 108MW of PRMR value to the utility.

Including the PRM % add back puts the LMR capacity value on an even playing field with unregistered LMM assets. LMR's are providing capacity value equivalent to their load reduction as well as the avoidance of carrying the extra PRM% risk margin.

How should MISO collect locational information for LMRs?

1. CPNode

MISO uses LMR's as tools for capacity emergencies, which are rarely (if ever) localized or declared in a region below the North/Central/South regions, and sometimes directed at the LBA level. MISO has not demonstrated how breaking up LMR's into EP Nodes or lower would provide tools to better serve capacity emergencies.

LMR's were not intended to be instruments to resolve transmission congestion. Locational Marginal Price is the prevailing tool to manage one side of a transmission constraint, which leads to the scheduling of assets in the Energy and Operating Reserve markets. LMR's don't participate in E&OR markets, but Demand Response Resources (DRR's) do.

I think MISO's reasoning for wanting to manage transmission constraints is sound, but LMR's are not the tool to use. DRR's are the tools to use for managing localized transmission constraints.