FERC on Tuesday approved Tariff revisions that will finally allow SPP to implement a resource adequacy requirement (RAR), reducing its planning reserve margin from 13.6% to 12% (ER18-1268).

The commission found the revisions will help ensure that sufficient capacity and planned reserves are maintained to meet SPP’s balancing authority load requirements. The proposal also clarifies the types of authorities that may impose rules considered force majeure events, defined as “any curtailment order, regulation or restriction imposed by governmental, military or lawfully established civilian authorities.”

SPP revised its filing after FERC rejected a previous submission in September 2017, the second time its RAR proposal was found to be deficient last year. (See FERC Again Rejects SPP’s Resource Adequacy Revision.)

The grid operator said its new Tariff Attachment AA includes all the terms and conditions relevant to the establishment, compliance and enforcement of the requirement that each load-responsible entity (LRE) in the SPP BA area maintain sufficient capacity and planning reserves to serve its forecasted load.

The RAR change will require LREs without sufficient generation to participate in bilateral capacity markets. FERC noted SPP’s current market is “relatively net long” compared to the planning reserve margin, and that “likely many sellers of capacity are available to meet LREs’ net peak demand and planning reserve margin.”

The commission said it “continue[s] to encourage SPP and its stakeholders to consider the potential for the exercise of market power in the market for bilateral capacity as the overall reserve margin potentially shrinks in the future.”

FERC suggested last year the proposal could be “more fully develop[ed].” It provided guidance that SPP require all power purchase agreements be backed by verifiable capacity; that the proposed treatment of firm power purchases and sales in the determination of net peak demand was unduly discriminatory; and that the RTO was unable to support its proposal to post publicly a list of all LREs unable to meet their RAR.

Westar Energy protested the most recent filing, separately and with Kansas Power Pool and Missouri Joint Municipal Electric Utility Commission. FERC sided with SPP in each of the arguments.

The RAR proposal is effective July 1, 2018. SPP said this would allow LREs to participate in a full cycle of the annual process before being exposed to a deficiency payment.

SPP’s Board of Directors and stakeholders approved a package of policies in January 2017 that included reducing the RTO’s planning reserve margin to 12%, which translates to a 10.7% capacity margin. LREs with resource mixes that are at least 75% hydro-based are allowed a planning reserve margin of 9.89%.

A stakeholder task force spent more than two years developing the package, which was projected to reduce SPP’s capacity needs by about 900 MW and save members $1.35 billion over 40 years. (See “Stakeholders Endorse 12% Planning Reserve Margin, Policies,” SPP Markets and Operations Policy Committee Briefs.)

SPP said it intends to recalculate the planning reserve margin every two years, “based on a probabilistic analysis using a loss-of-load expectation study.” Any future changes to the planning reserve margin must go through the RTO’s Regional State Committee, composed of state regulators, for approval.

Commission Rejects PMU Proposal over Cost Concerns

The commission rejected without prejudice to SPP a second Tariff change that would have required phasor measurement units (PMU) at new generator interconnections, saying the proposal’s language is unclear (ER18-1078).

The American Wind Energy Association argued against the Tariff proposal, questioning the extent to which transmission owners should be required to fund PMU installations. AWEA raised concerns that SPP did not address funding obligations and said that, as drafted, the proposal would have allowed TOs to exercise market power and force interconnection customers to fund installations.

FERC found the revision’s proposal to allow TOs the option to fund PMU installations only when their interconnection customers are affiliates “could result in affiliated interconnection customers having lower costs than non-affiliated interconnection customers.” That would give affiliates an undue competitive edge, the commission said.

The agency said SPP did not address how TOs would account for the costs of the installations for their own generators or those of affiliated interconnection customers, and how the costs would be treated under the transmission formula rates in order to prevent unreasonable and/or unduly discriminatory rates.

The commission said any subsequent SPP proposal should clarify how TOs will treat PMU installation costs to avoid including them in transmission rates. Doing so, it said, could effectively result in non-affiliate customers subsidizing installations for generators belonging to TOs and/or their affiliated interconnection customers.

FERC also said SPP should develop Tariff language regarding responsibility for ongoing PMU communication and operation and maintenance expenses, and clarify the extent to which the interconnection customer can use existing equipment, such as relays or digital fault recorders with phasor measurement capabilities, or provide data from PMUs already deployed and/or sited on the generator side of the interconnection point.

PMUs are devices that measure the voltage, frequency and angle of the grid’s electrical waves, using a common time source for synchronization. The devices can take samples hundreds of times a second, while the standard supervisory control and data acquisition systems can have scan rates of 10 to 30 seconds.

The proposal cleared SPP’s board and stakeholder groups in January.

— Tom Kleckner