FERC on Thursday issued a Notice of Inquiry (NOI) seeking comment on how reactive power capability should be compensated in the face of changing conditions on the nation’s electricity grid (RM22-2).
Unlike the “real” power generated on the grid, which provides energy to end-users (and is measured in watts), “reactive” power (measured in volt-amperes reactive) is needed to support voltages that allow power to flow along transmission lines, a necessary component of system reliability.
“At times, resources must either supply or consume reactive power in order for the transmission system to maintain the voltage levels required to reliably supply real power from generation to load,” FERC staff explained in a presentation during the commission’s open meeting Thursday.
FERC Order 888, issued in 1996, ruled that the reactive supply and voltage control supplied by generators is one of six ancillary services that transmission providers must include in their open access transmission tariffs. At the time, the commission pointed to two methods that providers used for managing voltage control: either installing equipment as part of the transmission system or relying on generation resources.
“The commission concluded that the costs associated with the first approach would be recovered as part of the cost of basic transmission service and, thus, would not be a separate ancillary service. The second, using generation resources, would be considered a separate ancillary service and must be unbundled from basic transmission service,” FERC staff said.
Order 888 was issued at a time when the country’s resource mix overwhelmingly consisted of synchronous generators containing mechanical rotors that rotate in sync with system frequency and generates both real and reactive power in response to the needs of the system.
As FERC staff noted Thursday, in 1999, the commission issued an opinion approving American Electric Power’s method for separately allocating the costs for synchronous generators between providing real power and reactive power capability, including operations and maintenance costs associated with each function.
“Subsequently, the commission recommended that all resources located in regions that base reactive power capability compensation on a resource’s individual costs and that have actual cost data and support documentation should use the AEP methodology when seeking to recover reactive power capability costs pursuant to individual cost-based revenue requirements,” staff noted.
But FERC’s recommendation did not constitute a mandate, and regions have adopted differing approaches to compensating generators for reactive power, with PJM, MISO and certain non-RTO regions generally relying on the AEP methodology, while ISO-NE and NYISO compensate based on a fixed rate multiplied by a resource’s tested reactive capability. CAISO, SPP and other non-organized markets do not compensate at all for reactive capability, FERC staff pointed out.
Existing arrangements for compensating reactive power remained sufficient until “a general shift away” from cost-of-service rates in the electric industry and the increased adoption of nonsynchronous — or inverter-based — renewable and energy storage resources, FERC staff said. Those resources do not use mechanical rotors that rotate in sync with the grid and must have their inverters configured to provide reactive power capability, among other services.
According to FERC staff, “the AEP methodology was designed based on the physical attributes of synchronous resources owned by a public utility that utilized the commission’s Uniform System of Accounts and annually submitted a FERC Form No. 1,” the annual financial and operating report submitted by regulated utilities.
But the commission is now finding that most of the reactive power rate schedule filings it receives are made by owners of non-synchronous resources exempted from the Uniform System of Accounts and Form 1, although they’re still subject to other reporting requirements. FERC staff said that in the last six years, the commission has processed at least 260 reactive power proceedings in PJM and 125 such proceedings in MISO.
“These factors have contributed to customers and the commission facing challenges in evaluating proposed reactive power rate schedules submitted pursuant to Section 205 of the Federal Power Act,” FERC staff said. “Therefore, the commission is seeking comment on various aspects of AEP methodology-based compensation; potential alternative methodologies; and reactive power capability compensation through transmission rates for resources that interconnect at the distribution level.”
“When I first arrived at FERC, I really didn’t have an idea we would be doing so many reactive power cases,” Chairman Richard Glick said during the commission’s open meeting Thursday. He noted that of the 395 total cases, the commission has sent 135 of them to its administrative law judges for settlement and hearing procedures. “I suspect there’s a better, more efficient way, and that is what this Notice of Inquiry is going to look into, among other issues.”
Commissioner James Danly thanked Glick for the NOI, saying “we’ve spent an inordinate amount of time on these cases without having a generic approach to them.”
“This is an important way to find efficiencies in the trenches and relieve staff to do other import work,” Commissioner Allison Clements agreed.
Comments on the NOI are due 60 days after its publication in the Federal Register.
