The DERs Aggregation rulemaking (now FERC Docket No. RM18-9) was initiated back in 2016 and was the subject of a 2018 Technical Conference. Now, FERC has posed to the six ISOs/RTOs an identical set of data requests regarding DERs that focus primarily on how interconnection service and distribution service would be provided to DERs. The data requests illustrate an issue discussed in a recent blog post about Order No. 2003 and FERC’s decision there to: 1) eliminate the bright line between its jurisdiction and state jurisdiction over interconnection service and replace it with a blurrier jurisdictional line that is referred to as the “first-use test” or “already subject to an OATT test”; and 2) retain the bright line between its jurisdiction and state jurisdiction over interconnection service when the seller is a qualifying facility (QF) that can sell to third parties. FERC’s questions reflect how complicated this policy is to implement (particularly as a non-QF may become a QF, thus shifting jurisdiction). The questions also indicate how difficult to even determine the role, if any, ISOs and RTOs take in DER interconnections by reviewing their filed tariffs. Taking FERC’s jurisdictional policies and ISO/RTO policies on whether to participate in the DERs interconnection process and applying them to an aggregation that may be comprised of QFs, non-QFs, demand response participants, and storage DERs raises a host of questions that many ISOs, RTOs, and Distribution Owners likely have not even considered. These questions may get those conversations started.

The answers to the questions will probably reveal several interesting things about how much, or how little, any particular ISO or RTO knows about interconnection processes for DERs. Some predictions of what FERC may learn from some of its questions are made below. These are only predictions. For brevity, the data requests are not repeated here. Continue Reading FERC’s ISO/RTO DERs Data Requests – What Do They Tell Us and What Will the Answers Likely Tell FERC

It is somewhat common for a utility to determine not to challenge a new rule on power purchases issued by its state commission that is clearly in violation of PURPA or the FPA. This reluctance is understandable and often rests on a political decision: fighting a state commission over an issue may have a greater downside than upside with regard to the continuing relationship between the utility and its regulators. Utilities also sometimes ignore the illegality of new state laws requiring them to purchase energy from certain sources or at certain rates. Developers are less inclined to defer to state legislatures or regulators and often will challenge laws or state commission orders that appear facially unlawful. But, as such challenges can be costly, some preemptable state laws and regulations in some cases go unchallenged. Allowing such laws and regulations to remain in place can lead to unforeseen impacts and expenses for purchasing utilities and developers alike. Continue Reading Preemptable State Laws and Regulations: The Failure to Challenge Can Have Adverse Impacts

In 2017, a California federal district held in Winding Creek v. CPUC that the California Public Utilities Commission (CPUC) had two PURPA problems: 1) its capped PURPA program entitled “Re-MAT” did not adopt an avoided-cost price because of its adjustment mechanism scheme; and 2) the CPUC’s standard PURPA contract (Standard Contract) failed to properly implement PURPA because the contract had only one, not two, pricing options. As a result, the court found that the cap on the Re-MAT program was improper. The district court found that the Standard Contract would need to provide a fixed price at the time of contracting and at delivery to satisfy FERC’s PURPA regulations. The district court also held that it was not its job to fix the Re-MAT pricing problem by setting an avoided cost price or requiring the purchasing utility to provide a contract at the “unadjusted” price demanded by the QF. Both sides appealed.

Yesterday, the Ninth Circuit ruled that the district court was correct as to all its findings. Perhaps of most importance, the Ninth Circuit concluded that a formula rate could not satisfy the requirement of 18 C.F.R. § 292.304(d)(2)(ii) of a price set at the time of contracting (i.e., when a legally enforceable obligation (LEO) is formed). It stated, that the “Standard Contract provides only one formula for calculating avoided cost, and that formula relies on variables that are unknown at the time of contracting.” Indeed, it found this “infirmity is plain from the face of the regulations, so we do not defer to FERC’s unreasoned conclusion to the contrary.” Continue Reading Ninth Circuit Affirms Winding Creek: Formula Rates Do Not Satisfy Price Set at Time of LEO

Several moths ago FERC issued an Intent Not to Act on New Mexico Public Regulation Commission’s (NMPRC) LEO standard, which (seemingly) was challenged by a QF’s (Great Divide) Petition for Enforcement under PURPA. The NMPRC had adopted a very strict LEO standard, that required that QFs must be ready to interconnect and deliver energy before any legally enforceable obligation may be created to purchase the power at avoided cost rates. Great Divide turned to federal district court for relief, as one might expect. There was an expectation that this case could provide some important guidance as to the current chasm between many purchasing utilities and the QF industry as to at what point of time a LEO should be found to have been established.

Instead, what the industry received was a lengthy order dissecting whether Great Divide had truly brought an implementation claim as opposed to an “as applied” claim. The court (2019 WL 2144829) found that Great Divide brought an “as applied” claim largely because Great Divide was challenging an NMPRC order finding it had no LEO rather than the rule (Rule 570) on which such order was based and/or the NMPRC’s interpretation of that rule. Continue Reading District Court Order Provides PURPA Guidance – On “As Applied” Versus Implementation Claims

On June 3, 2019, the US. Court of Appeals for the Ninth Circuit issued a Memorandum Opinion (i.e., not for publication), that reinforced the scope of the role of the district and appellate courts in cases brought under the juridical review scheme of PURPA. In the case below, the plaintiff QFs (Plaintiffs) had succeeded in convincing FERC (in a declaratory order ruling) that the Montana Public Service Commission’s (MPSC) legally enforceable obligation (LEO) standard violated PURPA and that the QFs were entitled to declaratory relief. The QF plaintiffs went to district court to obtain confirmation and an order that the LEO standard that the MPSC had applied was illegal. Before the district court could rule, however, the MPSC set a new LEO standard that it placed into effect prospectively. Nonetheless, the district court provided declaratory relief that the prior LEO standard was unlawful. Both the Plaintiffs and MPSC appealed.

The district court had left all interested parties (including with purchasing utility, Northwestern Energy) with no guidance as to what LEO standard should apply to the Plaintiffs and other QFs that were denied contracts under the illegal LEO standard. The QFs wanted guidance, the MPSC wanted the entire matter found moot. The Ninth Circuit agreed with the MPSC, holding that the district court erred in concluding it could reach the merits of Plaintiffs’ request for declaratory relief. The court found that the request for declaratory relief was moot, given that the MPSC regulation under challenge had been changed before the district court issued its ruling. Continue Reading Ninth Circuit Reinforces the Appropriate Role of Courts in PURPA Implementation Claims

The jurisdictional discussion in Order No. 841-A was lengthy. It could have been very short.

This blog today takes a personal turn as I relate the tale of FERC’s jurisdiction over energy storage resources (ESRs) connecting to a public utility’s distribution system to sell wholesale power. There is only reason that the tale is long (like this blog entry) – Order No. 2003.

In the bundled era, no one seemed to give much thought to the fact that FERC, and the FPC before that, regulated both the interconnection of and delivery of power to load-serving entities (LSEs), i.e., wholesale customers, connected to a public utility’s local distribution facilities. With unbundling and full open access on the horizon, however, FERC reiterated its policy in Tex-La:

“We do not agree with TU that the local distribution exception to our jurisdiction under section 201(b)(1) of the FPA precludes us from ordering under section 211 the transmission services requested by Tex-La. Section 211(a) of the FPA authorizes the Commission to require a transmitting utility: ‘to provide transmission services (including any enlargement of transmission capacity necessary to provide such services) to the applicant.’ Ordering ‘transmission services’ to the wholesale customer in this proceeding, whether or not that service consequently involves some use of facilities that may not be purely ‘transmission’ facilities, is doing no more than what we are authorized to do by the statute. It is not an assertion of jurisdiction over specific facilities, but rather is an assertion of authority to order specific services.”

With open access, the relatively few distributed energy resource (DERs) that were not QFs selling only to their host utility were typically interconnected pursuant to FERC jurisdiction.

In a case arising shortly after open access, involving interconnection service, but not delivery service for a new LSE, FERC, relying on Federal Power Act Section 210, made clear that when the FPA said that FERC could compel to electric utilities to interconnect to the “transmission facilities of any electric utility” Congress really meant “transmission or distribution facilities.” FERC explained in Laguna:

“PG&E has provided no persuasive rationale for us to read ‘transmission facilities’ in [S]ection 210 in a way that would vitiate the very purpose of the provision, i.e., the ability of an eligible applicant to obtain interconnection to a utility’s transmission grid. Under PG&E’s argument, the Commission would lack jurisdiction to order an interconnection any time nominally local distribution facilities arguably are involved. We do not believe that Congress intended for wholesale customers such as Laguna to be ineligible for an interconnection under [S]ection 210, based merely on the label attached to facilities to which they interconnect.”

Laguna stands for the simple proposition that if one electric utility asks another electric utility to interconnect, FPA Section 210 allows FERC to order that interconnection. An ESR (or any DER), that will sell electric energy presumably is an electric utility. Is the tale over? No. (Although perhaps it is over if an ESR is willing to seek interconnection service under FPA Section 210.)

In 2000, in Tennessee Power Company, FERC clarified that interconnection is a critical component of open access transmission service. In the very same year, the D.C. Circuit affirmed FERC’s assertion of jurisdiction of any wholesale transmission service (including distribution facilities), in Order No. 888, holding in TAPS v. FERC that “FERC’s assertion of jurisdiction over all wholesale transmissions, regardless of the nature of the facility, is clearly within the scope of its statutory authority.” A bright line had been set as to retail and wholesale usage of distribution. If interconnection service is transmission service and FERC has jurisdiction over all wholesale transmission service, even if it occurs on local distribution facilities, does that not mean (putting PURPA aside) that FERC has exclusive jurisdiction over: 1) interconnections to public utilities of entities buying and selling power at wholesale; and 2) the delivery of wholesale energy to or from such wholesale entities? Now, the tale must be over. Sorry, no.

How did DERs (including distributed ESRs) interconnection jurisdiction get so complicated after Tex-La, Laguna, Tennessee Power, and TAPS? Indeed, such jurisdiction got so complicated for a wholesale ESR, FERC is now saying in Order No. 841-A that “Order No. 841 did not mandate that electric storage resources must have access to the distribution system” and “Order No. 841 does not modify states’ authority to regulate the distribution system, including the terms of access.” The dissent goes further.

The tale might have ended had FERC adopted its Order No. 2003 NOPR position in Order No. 2003. In the NOPR, FERC embraced the bright line it had established in Order No. 888 and cases like those cited above, stating that it is “clear that the FPA grants federal jurisdiction over transmission by a public utility in interstate commerce and when public utilities make sales for resale in interstate commerce. Within this jurisdiction, we propose that the NOPR IA and IP will apply only when a generator interconnects to the Transmission Provider’s transmission system or makes wholesale sales in interstate commerce at either the transmission or distribution voltage level.” FERC was prepared to continue to exercise the jurisdiction it had exercised for years over interconnections of wholesale sellers (and more commonly wholesale buyers) to distribution facilities. Many states got angry. FERC blinked. Order No. 2003 was issued.

There, FERC found that some lower-voltage facilities are “local distribution” facilities not under its jurisdiction, but that some distribution facilities are used for jurisdictional service such as carrying power to or from a wholesale power customer and are included in a public utility’s OATT. Order No. 2003 was thus found to apply “to interconnections to the facilities of a public utility’s Transmission System that, at the time the interconnection is requested, may be used either to transmit electric energy in interstate commerce or to sell electric energy at wholesale in interstate commerce pursuant to a Commission-filed OATT.” The “first-use” test. The Commission also addressed QF interconnections in Order No. 2003, but did not mention that its first-use test would not apply to those QFs connected to distribution with the ability to sell to third parties, as it later would. Although the first-use test remains, the foundation on which it rested (that FERC only has authority to order interconnections to “already-used” distribution facilities), had already been abolished before the ink dried on Order No. 2003.

In Order No. 2003, FERC stated that it would exercise exclusive jurisdiction over the rates, terms, and conditions of Commission-jurisdictional service provided over “dual use distribution facilities.” But in a separate case, winding its way on appeal in the midst of the Order No. 2003 rulemaking, FERC argued that once any entity made a wholesale use of a local distribution facility, such now dual-use facility became exclusively FERC-jurisdictional. All service over dual-use distribution was FERC-jurisdictional according to FERC such that various “pieces” of each utility’s distribution system would not be subject to state jurisdiction when used by retail customers. Interestingly, this broad taking of jurisdiction from the states was challenged only by two utilities, and no states. A D.C. Circuit panel heard the Detroit Edison appeal and disagreed with FERC. The court explained that a local distribution facility used by a wholesale customer remained subject to state jurisdiction for retail purposes but that when a local distribution facility is used in a wholesale transaction, FERC has jurisdiction over that transaction pursuant to its wholesale jurisdiction under FPA § 201(b)(1). In other words, the D.C. Circuit supported a simple and clear bright line between state and federal jurisdiction over local distribution facilities. Wholesale uses belong to FERC; retail uses belong to the state. There were not in fact two “flavors” of distribution facilities each subject to the exclusive jurisdiction of either FERC or the state. FERC would have to address this new bright line on rehearing of Order No. 2003, as the case was issued too late for any commenters to use it to support FERC’s NOPR claim of jurisdiction over all wholesale DERs interconnections.

Now, those (very few) who objected to FERC’s change in position from the NOPR’s wholesale/retail test to Order No. 2003’s first-use test had strong ammunition. Well, they thought they did. One lawyer, whose name I refuse to disclose because I (oops!) failed to change FERC’s view in three separate clarification/rehearing requests, tried to use Detroit Edison to reinstate a simple bright line test. In Order No. 2003-C, FERC issued its final rejection of its NOPR claim of jurisdiction over all wholesale generator interconnections to distribution systems, explaining that asserting such jurisdiction “would allow a potential wholesale seller to cause the involuntary conversion of a facility previously used exclusively for state-jurisdictional interconnections and delivery, and subject to the exclusive jurisdiction of the state, into a facility also subject to the Commission’s interconnection jurisdiction – a result that we believe crosses the jurisdictional line established by Congress in the FPA.” (FERC expressed no concern about QFs selling to third parties and new wholesale loads causing the exact same conversion.) Had FERC instead ruled in Order No. 2003 that interconnection service was an element of transmission service and FERC has exclusive jurisdiction over all wholesale transmission even on distribution facilities, I personally believe that a court of appeals would have upheld that ruling. The selling of wholesale generator interconnection service certainly sounds like a wholesale transaction under the logic of Detroit Edison. But, FERC would not accept this position.

In short, by adopting the first-use test in Order No. 2003, FERC voluntarily narrowed its jurisdiction over wholesale usages of distribution facilities, at least as to generation interconnections. In contrast, FERC never seemed to relinquish jurisdiction over either wholesale load interconnections or any delivery service that requires the use of distribution facilities.

The entire jurisdictional portion of Order No. 841-A, thus, could not rest on cases such as Tex-La, TAPS, Detroit Edison, etc., that stand for the proposition of exclusive FERC jurisdiction over all wholesale distribution transactions (including generator interconnections) without reversing Order No. 2003’s exclusion as to some generator interconnections. In contrast, those cases, although not cited, are implicit once FERC starts discussing rates for wholesale delivery service that ESRs may have to pay to charge. The distribution delivery transaction remains exclusively FERC-jurisdictional after Order No. 2003. In Order No. 841-A, FERC stated that it “would consider any proposal to establish a rate for providing wholesale distribution service to an electric storage resource for its charging (whether a facility-specific rate, a wholesale distribution service rate that applies to all or some subset of electric storage resources, a generally applicable wholesale distribution service tariff, or any other rate mechanism) on a case-by-case basis in light of the record evidence.”

Order No. 2003 did not address FERC’s unquestioned exclusive jurisdiction over wholesale load interconnections. This point raises one final question and perhaps could have changed this tale’s ending if it had been raised in the Order No. 841 rulemaking: Just as an ESR needs an interconnection to discharge (and sell) energy, it needs an interconnection to buy the very wholesale power that Order No. 841 said it was entitled to buy. That is, an ESR is, in part, a wholesale load. Granted, an ESR may need only one physical interconnection, but rather than tying itself in knots over jurisdiction through cases such as EPSA and the “affects and relates to” clause of the FPA, a FERC ruling that the interconnection of a wholesale load to a public utility is a FERC-jurisdictional service would have been an easy way for FERC to find the interconnection jurisdiction it ceded away in Order No. 2003 as to ESRs. When one views ESRs as wholesale loads, the notion that FERC lacks authority over their interconnection to any distribution facility is implausible. The tale could have had a very different ending as to DERs that are ESRs had they been treated like LSEs.

But for now, the DERs interconnection jurisdiction tale ends with Order No. 2003. Its first-use test remains the law (except for those third-party selling QFs, some of which may well already have added storage or may add storage, and those DERs that may turn to FPA Section 210 given Laguna).

None of the discussion above is meant to undermine the argument that ESRs located on distribution systems can and likely will raise reliability, security, operational, cost causation, and myriad other difficult issues and challenges for utilities given sufficient penetration levels. Nor does the discussion above judge whether states or FERC are in a better position to address such issues. FERC likely could assert jurisdiction over wholesale interconnections and still permit a state to opt out. Rather, the discussion above is intended to point out that FERC’s distribution interconnection jurisdiction has ebbed and flowed over time. I have been lucky to have been both a frequent participant and intimate observer in these distribution interconnection jurisdiction skirmishes for over two decades. It appears such opportunities are not going away.

This blog article reflects only the personal viewpoint of its author, Jennifer Key.

“We hold only that where a utility uses energy from a QF to meet a state RPS, the avoided cost must be based on the sources that the utility could rely upon to meet the RPS.” Californians for Renewable Energy v. CPUC (CARE)

Wow! This ruling is now binding within the Ninth Circuit and could have ripple effects throughout the country.

In 2010, in CPUC v. SCE, FERC reversed several decades of PURPA policy and precedent on avoided costs, permitting States with Renewable Portfolio Standards (RPS) to base avoided cost rate calculations on the costs of other renewable resources regardless of whether alternative non-renewable sources were available at lower cost. This is referred to as “multi-tiered” avoided cost rates. The Ninth Circuit has now taken FERC’s re-interpretation of the rules for determining avoided cost rates a giant step further. Where FERC held that States have discretion to adopt multi-tiered avoided cost rates, the court in CARE turned it into a mandate.

The concept of multi-tiered avoided cost rates has always been legally questionable (and, indeed, has never been subjected to challenge before a court). It is legally suspect because it permits the States to set avoided costs that could impose higher costs on customers than they would have incurred absent the PURPA mandate. This runs contrary to the central principle behind avoided cost pricing according to FERC, which is to prevent the PURPA mandate from increasing a utility’s costs to serve its customers – that “utilities (and their ratepayers) be in the same financial position as if they had not purchased QF power.” As the Supreme Court explained, FERC’s adoption of full avoided cost requires utilities to pay “the same costs had they generated the energy themselves or purchased it from other sources” and, therefore, holds the utility and its customers harmless. PURPA, thus, compels utilities to buy from certain renewable generators, but caps the price based on the alternatives the utility would have built or bought absent the purchase mandate. In CARE, however, the Ninth Circuit arguably turned this principle on its head – with regard to any QF purchase made to meet an RPS. The decision forbids States from considering the costs of the generation resources the utility would have built or bought in the absence of PURPA.  Continue Reading Ninth Circuit Mandates Use of Multi-Tiered Avoided Cost Rates Where Utilities Make Purchases From QFs In Meeting Renewable Portfolio Standards


Yesterday, FERC issued an order on a Petition for Declaratory order from Sunrun, asking that FERC waive the QF certification filing requirements for separately-interconnected, individual residential rooftop solar PV systems and related equipment with maximum net power production of 20 kW or less that Sunrun provides financing for but which the homeowner has an option to purchase, where such 20 kW or less systems may aggregate to over 1 MW within a one-mile radius; and that in a Form No. 556 submitted for a cluster of rooftop PV systems that exceeds 20 kW, the Commission waive the requirement in Item 8a of Form No. 556 to include information regarding the facilities covered by the first requested waiver (i.e., 20 kW or less facilities), even if they are within one mile of the cluster that exceeds 20 kW that is being certified).

Although the Petition garnered minimal opposition, largely in the form of requests to delay action until (anticipated) PURPA reform occurred, FERC chose to act. FERC granted both waivers, agreeing with prior statements that solar generation facilities installed at residences or other relatively small electric consumers such as retail stores, hospitals, or schools do not present a compelling need for QF registration. The burden of such filings was considered to be too great in light of the lack of benefits. The second waiver was granted for similar reasons, as the fact that new client homeowners are added frequently and existing client homeowners may at any time exercise their option to purchase their 20-or-less kW PV systems would create a major burden on entities with business models such as Sunrun. Continue Reading FERC’s Sunrun Order Should Surprise No One, But May Lead to More Interesting Cases

Stampedes are dangerous. QF stampedes toward stale above-market standard avoided costs rates are dangerous to ratepayers. The first stampede occurred in the 1980s in California. California’s utilities were compelled to offer standard rates to QFs based on gas and oil prices at the time and then very shortly thereafter the bottom fell out of the oil and gas markets. California ratepayers paid for that stampede for decades. Stampedes toward stale avoided cost rates are continuing in various states today, particularly as solar generation prices have fallen rapidly. For example, Portland General reported that in Oregon, where standard rates are available for up to under 10 MW QFs, it has received 173 contract requests from sub-10 MW QFs. How state commissions, FERC, state courts, and federal courts all react to such stampedes will be discussed in future posts, as events unfold in various states. The experience of the Montana PSC in trying to stop a stampede illustrates the differences between the state and federal courts as relates to their authority to specifically set rates, terms, and conditions of PURPA contracts. In the case of the Montana PSC, a state court’s broad authority to set rates may exacerbate the impacts an existing QF stampede.

Both Northwestern Energy and the Montana PSC have been trying to fend off a stampede from 3 MW and smaller (mainly solar) QFs on numerous fronts, but were dealt a blow by a April 2, 2019 state district court order in Vote Solar v. Montana PSC that vacated certain Montana PSC orders. The most interesting aspect of the Cascade County District Court opinion was the fact that the court actually ordered the PSC to set rates, terms, and conditions of standard PURPA contracts in a particular manner.

By 2016, Northwestern recognized that a stampede was heading its way due to stale avoided cost rates for QFs of 3 MW or less. It took several proactive steps to have the Montana PSC protect its ratepayers. The Montana PSC lowered the standard avoided cost rate, limited what size QFs were permitted to request the standard avoided cost rate, reduced the length of the term of standard contracts, and affirmed its legally enforceable obligation (LEO) standard. Continue Reading The Montana QF Stampede and the Varying Roles of the Judiciary in Enforcing PURPA

On April 1, 2019, FERC issued deficiency letters to all the ISOs/RTOs that submitted Order No. 841 (Storage Rule) compliance filings: CAISO, ISO-NE, MISO, NYISO, and PJM. Generally such letters ask the RTOs and ISOs to explain in much greater detail how their tariff provisions permit energy storage resources (ESRs) to participate in their markets. It appears that FERC wants each requirement imposed by Order No. 841 to be discussed in the specific context of ESRs, such that if a tariff provision does not specify that ESRs are covered or subject to a provision, the ISO or RTO must explain why the provision nonetheless applies to ESRs. There are only a handful of Order No. 841 compliance deficiency letter issues relevant to distribution-connected ESRs (i.e., a form of DER). The most interesting question actually arguably is relevant to both distributed ESRs and transmission-connected ESRs, although in one deficiency letter (MISO) the question was asked only as to distributed-ESRs. That question is: How is the ISO/RTO is going to prevent ESRs from paying twice for “charging for later discharge” energy? It will be interesting to see what “prevention methods” FERC finds adequate.

Under Order No. 841, FERC found that an ESR should pay the wholesale market price (the nodal LMP in particular) for charging energy used for later discharge in the wholesale market. FERC was not “persuaded by commenters who argue that developing metering practices that distinguish between wholesale and retail activity is impractically complex.” Even though FERC expects that wholesale and retail loads typically can be distinguished, it did recognize that, particularly for distributed DERs with retail load, the task may be too complex. In Paragraph 321 of Order No. 841, FERC stated: “we require each RTO/ISO to prevent resources using the participation model for electric storage resources from paying twice for the same charging energy. To the extent that the host distribution utility is unable – due to a lack of the necessary metering infrastructure and accounting practices – or unwilling to net out any energy purchases associated with a resource using the participation model for electric storage resources’ wholesale charging activities from the host customer’s retail bill, the RTO/ISO would be prevented from charging that resource using the participation model for electric storage resources electric wholesale rates for the charging energy for which it is already paying retail rates.”

This paragraph gives ISOs and RTOs an “out” if a distributed ESR is located within a distribution utility that will not net out wholesale purchases from the retail bill. In such cases, the RTO/ISO should not bill the ESR at wholesale for its charging energy. Indeed, where load is not distinguished, answering FERC’s deficiency letter question may be quite simple. Several ISOs/RTOs explained on compliance that they would not assess a wholesale charge unless the retail and wholesale loads could be distinguished:

  • MISO Tariff Attachment HHH, Section 6 states “To the extent the [ESR] is paying retail rates for energy associated with wholesale charging activities, the [ESR] shall complete Appendix 3 to this agreement in order for MISO to exclude settlement at wholesale prices for the same charging energy.”
  • The CAISO provided ESRs several options, including one where the CAISO does not charge such ESRs for their charging because the distribution utility already has done so at a retail rate.

The difficult and interesting question is what happens if the ISO/RTO has a method for distinguishing wholesale and retail load. Continue Reading Order No. 841 (Storage Final Rule) Deficiency Letters – The Double Charging Issue