TULSA, Okla. — SPP’s Regional State Committee last week endorsed a policy white paper intended to ensure all net peak demand is carrying the appropriate capacity, as mandated by the RTO’s resource adequacy requirements.
The Distributed Energy Resource Policy addresses whether each DER is treated strictly as a modifier for a load-responsible entity’s (LRE) load or as capacity. Resources identified under the policy do not meet the requirements for firm capacity or deliverable capacity, as defined by SPP’s Tariff.
The paper defines DERs as either “controllable and dispatchable demand responses” (CDDRs) or “controllable and dispatchable” resources (CDRs).
CDDR is a specific program used to reduce LREs’ forecasted peak demand. The resources are not considered as capacity resources, even if they’re registered in the Integrated Marketplace, and can be controlled or dispatched by SPP or the LRE.
CDRs are defined as LRE-controlled or -dispatched resources not registered in the market or not a designated resource. However, they must be able to attest to having firm delivery to load. CDRs cannot be used as a load modifier unless they are non-controllable or non-dispatchable.
The white paper was unanimously endorsed in December by the Cost Allocation Working Group, which reports to the RSC. It has also been endorsed by the Supply Adequacy Working Group, which drafted the paper, and the Markets and Operations Policy Committee. (See “DER White Paper Gains Endorsement,” SPP MOPC Briefs: April 16-17, 2019.)
The white paper will be turned into a business practice and eventually become an attachment to the Tariff’s Attachment AA.
Market Monitors Develop Seams Issues
Adam McKinnie, an economist with the Missouri Public Service Commission, told stakeholders that a joint committee of SPP and MISO regulators is reviewing seams topics for potential development, as suggested by the RTOs’ market monitors.
McKinnie said the SPP RSC-OMS Seams Liaison Committee will have further discussion with the monitors to develop a scope for the work, which the committee expects to finalize in May.
The topics include how transmission planning assumptions limit the ability to identify joint projects; whether rules unique to each market affect seams; whether transaction scheduling/interface pricing can be improved to ensure beneficial market outcomes; and the effectiveness of the RTOs’ market-to-market process.
The committee will likely meet in person during the National Association of Regulatory Utility Commissioners’ July meeting in Indianapolis.
— Tom Kleckner
