In Order No. 2003, FERC adopted a very clear policy – that if a vertically-integrated transmission provider charged its OATT customers for reactive power from its own generating fleet under OATT Schedule 2, it had to allow other generators in its BAA (f/k/a control area) to be compensated for reactive power as well. This meant merchant and public power (non-jurisdictional) generators could file seek reactive compensation, regardless of the transmission provider’s need for additional reactive power. Implementation of the policy was not quite so simple because not all transmission providers were vertically-integrated. RTOs/ISOs had to make their own decisions as to whether generators would be compensated for reactive power. Some RTOs/ISOs decided any generator could obtain compensation (e.g., PJM); some decided no generator could (e.g., CAISO). In any case, the question arises what does eligibility for reactive power compensation have to do with a PURPA and DER blog? The subject is relevant because FERC has yet to provide clear answers in all cases as to QF and DER eligibility for reactive compensation.
Under What Facts Can QFs Obtain Reactive Power Compensation?
As a preliminary matter, QFs selling their output to a utility under PURPA tend not to seek reactive compensation, presumably because the purchasing utility would argue that given that they are paying (at least) an avoided cost rate, the purchaser is entitled to all products that constitute the QF’s output. Although a few non-QFs have litigated such issue with purchasers under PPAs at FERC, the issue of whether a QF has any reactive power to sell under a state-jurisdictional PURPA PPA would presumably fall under the jurisdiction of a state commission. The issue of whether the state-avoided cost rate included compensation for reactive did arise in the past year at FERC, but FERC sidestepped the issue and ultimately rejected the QF’s compensation request filing on jurisdictional grounds, as discussed below.
Specifically, in its rehearing order in Cherokee County Cogeneration Partners, LLC, FERC held that if a QF is selling its full output under PURPA, i.e., pursuant to a state program, FERC lacks jurisdiction over any sale of reactive power such QF wants to make. In so ruling, FERC skirted the issue of whether the QF had any reactive power to sell, and instead assumed that if there was any reactive power to sell, that the sale was not FERC-jurisdictional. Although some older cases had similar outcomes, FERC provided greater detail as to its position in Cherokee. Specifically, FERC found that the exemption from FPA Section 205 jurisdiction provided for in 18 C.F.R. § 292.601(c)(1) encompassed the reactive service at issue. FERC explained that the terms “energy and capacity” used in that regulation included ancillary services, noting that it had stated that “[i]n the context of PURPA, the term energy includes capacity, energy and ancillary services.” That is, because the QF was exempt from FPA rate regulation due to its sales under a state PURPA program, it could not file a FERC-regulated rate for reactive power.
What is most interesting about this order, or arguably most confusing, is that QFs selling power under the other Section 205 exemption also found in 18 C.F.R. § 292.601(c)(1) evidently are free to sell reactive power at FERC-regulated rates. 18 C.F.R. Section 292.601(c)(1) states in relevant part that “sales of energy or capacity made by qualifying facilities 20 MW or smaller, or made pursuant to a contract executed on or before March 17, 2006 or made pursuant to a state regulatory authority’s implementation of section 210 [of PURPA] shall be exempt from scrutiny under sections 205 and 206.” Emphasis added. In Hillman Power Company, L.L.C., a 20 MW QF selling power under a PPA, which presumably was not a PURPA PPA (as if it was a PURPA PPA the case is in direct conflict with Cherokee, filed a reactive rate to obtain reactive compensation from MISO. Although the Commission evidently lacked any jurisdiction over Hillman’s sales of energy and capacity under a different clause of the very same regulation (292.601(c)(1), i.e., the 20 MW clause, not the sales made pursuant to a state regulatory authority’s implementation of PURPA clause, the Commission accepted the rate schedule and set it for hearing. The issue of FERC jurisdiction did not arise. The case settled with an interim rate being permitted to take effect October 1, 2013. (No appropriate filing was made in eTariff to implement this effective date, although the MISO OASIS indicates the rate is effective.)
Perhaps the key difference was that Hillman was selling to an ISO, because the other confusing aspect of the Cherokee order is that generators owned by non-jurisdictional entities fairly routinely file at FERC seeking reactive compensation for their generation, at least in ISOs. Order No. 2003, however, indicated that non-jurisdictional entities generally could obtain reactive compensation from any transmission provider (not just ISOs/RTOs), despite their rates not being jurisdictional. How and whether any non-jurisdictional entity-owned generators are receiving reactive compensation from non-ISO/RTO transmission providers is less clear. In short, the Cherokee case arguably leaves open the issues of whether a QF that is subject to the 292.601(c)(1) exemption due to it selling to its host utility, can both prove it is has any reactive power to sell (a state PURPA issue) and how it would open such compensation that Order No. 2003 indicates that it is entitled to, if the first condition is met.
QFs not subject to the 18 C.F.R. § 292.601(c)(1) exemption at all, also have been selling reactive power for years and there is no controversy or question there, as they file FERC-jurisdictional rates.
Should DERs Be Eligible for Reactive Compensation, Where Otherwise Available?
The PJM Market Monitor has insisted in pleadings in at least four cases, that DERs are not entitled to reactive power compensation under PJM’s Schedule 2. Its position is that DERs have no obligations beyond those to the distribution system, that PJM lacks authority to dispatch DERs to provide reactive support for the PJM transmission system, and that PJM’s Schedule 2 does not obligate PJM transmission customers to pay for reactive capability provided to neighboring systems that only incidentally supports the PJM transmission system. The Market Monitor has not won this issue summarily to date, but it may be the reason no cases in which the issue was raised have settled to date.
Judging by the fact two of the four cases have reached an impasse (recently) and no settlement has been reached in any of the four cases, this issue presumably will be going to hearing. Although somewhat unclear, it does not appear that FERC has resolved this issue on the merits previously. Perhaps there are DERs that have obtained reactive compensation from FERC, but the majority of DERs are QFs selling to the host under PURPA and would not be eligible to seek compensation at FERC for the reasons explained above. As more stand-alone storage (i.e., non-QF resources) locates on distribution systems, the issue of reactive compensation may become more heated, leaving the two dockets that appear to be the first headed to hearing (ER21-1633 and ER20-1851), important bellwethers.