“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

On February 7, 2019, comments were submitted to FERC on the six RTO/ISO Order No. 841 (storage) compliance filings. FERC will need to address several issues regarding energy storage resources (ESRs), which are also distributed energy resources (DERs). This summary does not address issues that apply to all ESRs, such as limits on qualifying for capacity payments, transmission charges being properly excluded, PJM’s 10-hour rule, etc. Rather, it focuses on comments relating to ESRs that are also DERs or are quite likely to be DERs. For example, if an issue raised assumes that the ESR is co-located with retail load, that issue is likely to involve DER ESRs.

Overarching DER ESR Concerns

The comments relating to DER ESRs reflect many similar concerns – namely that the ISO/RTO is not including in its tariff sufficient information about matters relating to the state-federal jurisdictional overlap. Such alleged “omissions,” however, may reflect a lack of knowledge of the degree to which similar issues have been resolved in the non-ESR DERs context. Moreover, distribution owners (DO) (not the ISO/RTO) should be setting terms and conditions for DER ESRs’ usage of DO systems, in the first instance, subject to state commission or FERC oversight, if the DO is regulated.

Advanced Energy Economy, Tesla, and EDF Renewables all raise similar concerns that the ISOs and RTOs has not explained how DER and behind-the-meter (BTM) ESRs will access wholesale markets. This claim is somewhat odd in that DERs and BTM DERs have been accessing wholesale markets for decades in many states. Presumably, DER ESRs (whether BTM or in front-of the meter (IFOM)) will use the same processes and tools to interconnect and obtain service from their local utility to participate in the wholesale market as DERs use today. If such tools do not exist because of a lack of DERs, there are numerous states and DOs that can serve as models. There is nothing special or unusual about DERs participating in wholesale markets other than they (1) typically need to interconnect by asking their DO, rather than their ISO/RTO for interconnection service, (2) need to obtain wholesale distribution service (WDS) to sell some FERC-jurisdictional products to the market, and (3) DER ESRs will need WDS for charging purposes (when charging to resell). Only item (3) is unique to ESRs.

Comments such as those submitted by DTE Electric Company (DTE) indicate that some DOs evidently have not had to address market DER participation and are not yet prepared for such participation. For example, DTE is concerned with MISO providing dispatch instructions to DER ESRs due to a lack of visibility. DTE also is concerned with conflicting directions being issued by the DO and MISO. Yet, these are all issues any DER participating in MISO’s wholesale markets today would have to deal with, regardless of Order No. 841. Where a DO is providing a state-jurisdictional service, it can turn to its state commission (or if unregulated, to itself) to propose appropriate rules and protections; where a DO is providing a FERC-jurisdictional WDS, it has the right to set the terms and conditions for such service in the first instance. FERC-jurisdictional interconnection service for DER ESRs, largely will have to abide by the pro forma SGIA, as perhaps modified to reflect the ISO/RTO’s existence.

Advanced Energy Economy also raises in all dockets a concern about an ESRs’ opportunity costs where the ESR is co-located with retail load. Advanced Energy Economy argues that “opportunity costs are a key component of an ESR’s reference level” and that certain ESRs are used to ensure that a given [retail] customer’s demand does not exceed a certain threshold level. FERC, however, in developing market mitigation for ESRs should not consider an ESR’s role regarding managing the retail demand charge assessed a co-located retail customer. Wholesale and retail market considerations should be separated. FERC’s concern is wholesale markets, an ESR should not be permitted to set its wholesale opportunity cost based on retail rates.

Some of the more specific concerns of DERs and DOs are discussed below. Continue Reading DER Issues Raised by Storage Compliance Filing Comments

Updating the Year in Review on Legally Enforceable Obligations (LEO), FERC issued an Intent Not to Act on New Mexico Public Regulation Commission’s (NMPRC) LEO standard, which was challenged by a QF’s (Great Divide) Petition for Enforcement under PURPA.  It is not remarkable that FERC decided not to bring an enforcement action against the NMPRC LEO standard, which provides that a QF must demonstrate that it is ready to interconnect and deliver energy before a LEO is recognized.  (A similar LEO standard in Texas has already been upheld by the Fifth Circuit.)  What is interesting about the FERC order is the lengths that the FERC went to in explain that its failure to act was “meaningless.”  FERC explained that:

Notices of Intent Not to Act in the absence of an associated declaratory order cannot be read to mean that the Commission has accepted or agreed with (or alternatively, rejected or disagreed with) any argument made by any party, or with any substantive determination by a state regulatory authority or unregulated electric utility described in the petition for enforcement. The Commission’s silence is not evidence of a Commission determination on the merits of the parties’ arguments.  That is, the Commission has not ruled on the issues, and such issues may not be considered as having been so decided as to constitute precedents.  In sum, a Notice of Intent Not to Act, without an associated declaratory order, does not mean anything other than what it says – that the Commission declines to initiate an enforcement action under PURPA in response to the petition for enforcement.

What drove this rather strong addition to the FERC order? Although speculating, the answer is likely a split (2-2) among FERC Commissioners.  The NMPRC LEO standard is rather strict, and the only PURPA Enforcement action taken by FERC was against Idaho’s “utility must sign a PPA” LEO standard.  There may well have been two votes to bring an Enforcement Action and two votes against.  Those that that opposed this LEO standard may have insisted on the above wording to try and prevent a court “deferring” to FERC’s inaction.

FERC, not surprisingly, has asserted jurisdiction over the “inbound” wholesale distribution service (WDS) required by distributed storage resources that participate in FERC-jurisdictional energy and ancillary service markets (Wholesale Storage DERs). Although FERC has long asserted jurisdiction over WDS, it addressed charging Wholesale Storage DERs several years ago in a case involving Commonwealth Edison and Energy Vault.  There, FERC explained that ComEd may recover the costs of the use of its distribution system by Energy Vault, provided such recovery is just and reasonable.  That said, as Wholesale Storage DERs increase their market penetration, issues arise as to how distribution owners (DOs) should set rates for WDS and differentiate between wholesale and retail energy delivered to Wholesale Storage DERs and co-located retail load.  There are two primary challenges relating to developing and assessing WDS rates for Wholesale Storage DERs – 1) FERC’s general policy preferring that WDS rates be direct-assignment rates rather than rolled-in rates; and 2) separating energy delivered to co-located retail load (including station power load) from the energy delivered that will be resold into the wholesale market.  (“Outbound” WDS is a different issue as several DOs have made the decision not to charge for such service at all, outside of interconnection-related upgrades.)

FERC generally prefers that rates for WDS be customer-specific, reflecting the costs of the actual facilities used by DERs or other wholesale load. That is, rates for WDS are supposed to be determined on a direct assignment basis; the ComEd/Energy Vault case also reflects this policy.  At some point, however, Wholesale Storage DERs’ penetration may increase to a level where the ratemaking task becomes overwhelming and non-customer-specific rates for charging Wholesale Storage DERs will be necessary to relieve that ratemaking and regulatory burden.  FERC has permitted rolled-in pricing for WDS rates, but the (relatively small) utility in that case, argued that its wholesale distribution facilities operate as a single, integrated system consisting of mostly networked and looped facilities rather than a collection of radial segments off the transmission system, for which the specific costs can not be easily assigned to particular customers.  There is some likelihood FERC will allow additional utilities to adopt rolled-in pricing approaches.  One option for DOs is to ask FERC to use the state-approved retail distribution rate, but this approach is difficult to implement if a DO is located in a state that has not fully unbundled its retail rates, such that charges for other services are embedded in their retail distribution rates.  It does not appear that many DOs have had to deal with a level of Wholesale Storage DERs penetration yet.  That said, direct assignment rates likely will become unwieldy for some DOs in the relatively near future.

The second challenge facing DOs is the fact that Wholesale Storage DERs may be located behind the same retail meter as retail load unrelated to the Wholesale Storage DER or a Wholesale Storage DER will likely have (retail) station power load. Options such as mandating dual metering to separate the wholesale and retail load is one solution, but can prove expensive and may not be acceptable to retail regulators seeking to encourage distributed storage.  FERC recognized this issue in Order No. 841 and has indicated dual meters may be required for transmission-connected storage facilities, but it did not indicate whether this dual-meter solution could be mandated for Wholesale Storage DERs, where it may lack jurisdiction over the metering requirements, i.e., particularly where the interconnection of the Wholesale Storage DER is state-jurisdictional under the “first-use” test.  Continue Reading Charging Storage Load – Distribution Owner Challenges Regarding Inbound Wholesale Distribution Service

The Legally Enforceable Obligation (LEO) concept is a construct of FERC that is used in one of FERC’s avoided cost pricing regulations, i.e., 18 CFR § 292.304(d)(2)(ii).  The date a LEO is formed is the date a QF is entitled to have its avoided cost rate determined, if it so elects.  Through the decades, state utility commissions have adopted a quite broad array of standards for when a QF has established a LEO with a purchasing electric utility.  In providing non-binding guidance on the topic, FERC has had relatively little to say about the LEO standard other than that the purchasing utility cannot control LEO formation by its own action or inaction, such as a refusal to sign a contract.  For example, FERC has opined that the LEO standard cannot depend on the willingness of the purchasing utility executing a contract with the QF, whether it be a power purchase agreement.  In 2016, FERC expanded on that view, opining that a state may not require that a purchasing utility sign an interconnection agreement before a LEO is formed.  In 2018, several states examined their LEO standards.

Early in the year, the Vermont Public Utility Commission upheld its rule that a LEO cannot be formed until regulatory approval of a proposed power purchase agreement by the Vermont PUC.

As a result of various legal actions, the Colorado Public Service Commission eventually changed its regulations to ensure that a QF could obtain a LEO without winning a competitive solicitation.

In a case before the Minnesota Public Utilities Commission, the state commission looked for a QF to have made a “substantial commitment” and found that one had been made (and a LEO formed) when a QF:  (1) had paid for the Facility Study, which established how interconnection could be achieved, (2) had executed a Land Lease and Wind Easement, (3) had obtained necessary approvals from government entities, (4) had wind study results, (5) had reserved equipment, and (6) had filed the Complaint with the Commission. Continue Reading The Formation of Legally Enforceable Obligations: The Year in Review (2018)

As the industry continues to await action from FERC on PURPA in Docket AD16-16 or through a new rulemaking, various parties have submitted comments or pleadings in that docket and in other cases, that effectively take the position that QFs should not be accountable for knowing the laws and regulations to which they are subject. This same mindset may repeat itself when FERC adopts a Final Rule DER aggregation

As to PURPA, in August 2018 comments submitted by North American BioFuels (BioFuels), the company proposed making it a requirement that the purchasing utility to have received a copy of the Form 556 (or the equivalent) before the utility starts purchasing power from a QF.  That is, BioFuels proposes to shift the burden to the utility to ensure that a QF is in compliance with the law before buying power.  And, BioFuels seeks an amnesty period for QFs currently not in compliance with FERC’s requirements.  In October 2018, BioFuels enhanced its proposal with a legal paper suggesting that FERC has acted unlawfully in applying its standard time-value refund penalty for late-filed tariffs and agreements to QF-eligible entities who fail to timely file their self-certification form.  In a similar vein, QFs continue to argue to FERC in individual cases that the time-value refund penalty should not be imposed on them.  FERC generally has held steady in rejecting such pleas for relief in cases such as IGS ORIX Solar I.  Some QFs, such as York Haven, are taking these arguments further, arguing that QFs should be able to recover all of their fixed costs, thus effectively eliminating the time-value refund penalty.

Given that FERC provided notice to the QF community by issuing a rulemaking in 2005, these “remedies” are hardly necessary.  FERC has no broader way to communicate to the public than a rulemaking.  The time between the rulemaking being issued and the Final Rule (Order No. 671) being made effective that adopted the QF self-certification approach was about six months, plenty of time for a compliance process that BioFuels admits for renewable QFs is as “easy as pie” and takes only about 30 minutes.  Moreover, in the cases imposing the time-value refund penalties, FERC otherwise has excused late-filing QFs from the myriad other burdens of acting as public utilities for what has in some cases been years (i.e., MBR Tariff filing, EQR, etc.).  The “It should not be a QF’s responsibility to read FERC rulemakings” attitude reflects is troubling.  “Ignorance of the law IS an excuse!” is a very poor policy when it comes to electricity, which, although a product that provides light, is a product that cannot be taken lightly.  When laws and regulations concerning electricity are not followed, the results can be lethal. Continue Reading QF & DERs: Ignorance of the Law Is No Excuse

Over the last several weeks, a variety of entities have filed Petitions for Declaratory Order (PDO) or Enforcement Petitions relating to PURPA that may prove interesting to watch.

Sunrun asked FERC to make an exception for the need to self-certify (through Form 556) QFs under common ownership that total in aggregate more than 1 MW of capacity if all the QFs are located with one mile of one another, but only if such aggregation includes only QFs that are under 20 kW residential solar systems where the customer has a purchase option.  (Sunrun often leases solar systems with an option to buy, thus its desire to avoid the complexities of trying to determine when the 1 MW minimum for self-certification is met.)  This PDO may prove less controversial than some of the others recently filed.

Redlake Falls challenged a Minnesota PUC decision regarding what a utility’s avoided cost was at the time the legally-enforceable obligation (LEO) was formed, in a dispute that involves which rate proposed by various entities best represents avoided cost at the time the LEO was established.  This is not the type of PURPA Enforcement case that FERC is likely to bring an enforcement action itself, but a request was made for a PDO, so some non-binding guidance may be issued.

The two-decade battle between the Swecker family and Midland Power Cooperative and its supplier (Central Iowa Power Cooperative) continues unabated. This case cannot been deemed controversial, as the very same PURPA arguments have now been made and rejected repeatedly by any number of venues.  The most interesting issue to watch in the latest proceeding is whether Midland will finally obtain a suspension of the Sweckers’ rights to bring enforcement actions against Midland and CIPCO that raise the same avoided cost rate scheme.

Finally, in perhaps the most interesting case of the lot, NorthWestern petitioned FERC for a declaratory order determining that:

  • in periods when a utility has excess generation and cannot back down its generation, the avoided cost paid by the utility for energy to QFs should be zero; and
  • nothing in PURPA, including the rule against “non-discrimination” in pricing of avoided cost, permits setting a QF purchase rate above the utility’s avoided cost.

Continue Reading FERC to Address Several PURPA Issues In Coming Weeks and Months