On February 7, 2024, at the request of the U.S. Department of Energy (DOE), NAESB held a kick-off meeting for the development of a standard model contract to facilitate purchases by distribution owners of “distribution services” from DER aggregators. The idea is for NAESB to develop a standard contract that could be used by distribution owners nationally to allow DER aggregators to sell them distribution services. Unlike Order No. 2222, which mandated participation in ISO/RTO markets by DER Aggregators, whether a distribution owner must purchase services (and which services) from DER Aggregators is a decision that each state commission and local regulatory authority would make on its own. And, each such regulatory body can of course develop its own contracts. Distribution owners could voluntarily opt to use the standard contract for programs as well.

The NAESB standard contract is not designed for sales of demand response, which is logical, given that many distribution owners already have demand response programs in place. Rather, according to a NAESB agenda document, the covered distribution services would include Distribution Capacity, Voltage-Reactive Power, Reliability, Resilience, Energy, and Power Quality. At the kickoff meeting, the fact that sales of energy to distribution owners (i.e., load serving entities) by DER Aggregators would be FERC-jurisdictional and thus energy did not seem to belong in a contract for the sale of state-jurisdictional services was discussed. Energy likely will not be included in the final standard contract, although efforts by some to narrow FERC’s existing jurisdiction over wholesale sales were mentioned.

This NAESB effort, even though it would result in a product that may or may not gain any traction nationally, raises issues similar to Order No. 2222.

One issue discussed at the kickoff meeting was that the NAESB standard aggregation contract should ensure that a DER Aggregator for state-jurisdictional services is not prohibited from serving as a DER Aggregator, presumably for the same DERs, for FERC-jurisdictional services, under Order No. 2222. Although ISO/RTO Order No. 2222 aggregation programs assume that the ISO/RTO will have dispatch control over the DER Aggregator, how exactly a DER Aggregator could be required to follow orders from the ISO/RTO and a distribution owner appears to be an issue outside the scope of the NAESB project. It is unclear how the NAESB standard contract will address dual participation if such dual participation would run afoul of the requirements of participation in an Order No. 2222 aggregation (i.e., by allowing distribution owner dispatch). That said, given that FERC-jurisdictional DER aggregation is quite rare in areas where it is already an available business model (CAISO/NYISO), this is a dilemma that may never need to be solved.

The kickoff meeting did not address the need for the standard contract, as it appears such decision already had been made. But it remains unclear why DERs would be willing to forego existing state programs for a DER aggregation. Participating, for example, in full net metering is far more lucrative, presumably, than selling “distribution services” to a DER aggregator. There may be states willing to permit net metered customers to earn additional revenues, but distribution owners may balk at the cost and argue double compensation is occurring, just as they have in Order No. 2222 proceedings. Moreover, there is a trend in net metering (and other DER programs) to not net kWh but to pay (in credits) a “stack of values” to DER participants, which stack typically includes the equivalent of resiliency or reliability services, as well as future distribution deferral.

Given the vast array of existing state-jurisdictional programs for DERs with many, many different approaches to compensation, NAESB’s task becomes all the more challenging. Depending on what state program, if any, a DER already participates in, likely will govern what, if any, additional “distribution services” it may sell through a DER Aggregator. A one-size fits all contract will not work if DER eligibility for compensation depends on what compensation each DER already is earning. Disputes almost certainly will emerge over double compensation.

Another issue not addressed at the kickoff meeting is that some existing state programs under which DERs are paid to defer distribution capacity additions, compensation often reflects the full cost of the DER (and its operation), such that the value of the sale of energy or other products produced by the DER flows to ratepayers because the DER already has had its cost of service covered by such ratepayers. A state that takes such approach with DERs in an aggregation, would need to prohibit that DER from receiving any additional revenues that do not accrue to the ratepayers that paid for the DER. How the standard contract would address this issue should be considered, but again, compensation schemes could vary widely from state to state.

If a state commission adopts the ultimate NAESB standard contract product for use by regulated distribution owners, careful consideration will be required as to eligibility for compensation, as well as reasonable compensation levels. Utilities also should consider whether they should be seeking changes or clarifications to existing DER programs in order to prohibit DER aggregation that would result in additional compensation for products and services already reflected in existing compensation. Appropriate compensation for DERs, and the impacts of such compensation on ratepayers, remains a controversial topic and will for years to come, given the differentials among states in DER penetration. The Minnesota commission’s recent vote to reduce solar garden compensation reflects this fact.

Back in March of 2023, FERC issued a seemingly logical compliance order regarding one aspect of PJM’s Order No. 2222 compliance filing. This blog noted that “FERC acknowledged that DER owners in full retail NEM programs actually are compensated for ancillary services that they do not even provide and that paying them for ancillary services, assuming they could provide them, would be double counting. … Although further clarity will result on compliance, the decision reflects a breakthrough of sorts …. The fact that the Pennsylvania PUC expressed concern over double counting as to ancillary services in particular perhaps swayed FERC into recognizing the level of compensation offered by some NEM programs.” Perhaps this reading, that FERC might prohibit double compensation for the same service, was too optimistic.

That March 1, 2023 order also stated that: 

PJM’s proposed tariff requires an assessment of whether the “same product is not also credited” rather than whether, as the Commission discussed in Order No. 2222, the same service is being provided by the Component DER.  Being credited for a product may not be the same as providing a service.  This difference may be relevant because a Component DER participating in a net energy metering retail program, for example, may be credited for a product or service that it does not actually provide.

Continue Reading Double-Provision Versus Double-Compensation of Ancillary Services Under PJM’s Order No. 2222 Compliance Filing

PJM has long permitted generators to collect revenues for the provision of reactive power and voltage support (reactive power) under Schedule 2 of the PJM Tariff. Innumerable generating facilities have availed themselves of this opportunity. Nearly every such reactive revenue requirement case has settled. Although the vast majority of PJM transmission owners (TOs), whose ratepayers pay the majority of the reactive power rates, have divested their generation, few Transmission Owners (TOs), and fewer state commissions/consumer advocates representing such retail ratepayers, challenge these reactive revenue requirement filings. For some years, this left FERC Trial Staff as the only adverse participant, as regardless of the lack of protests in such cases, FERC usually suspends the revenue requirements and sets it for settlement and hearing. In recent years, however, PJM’s Independent Market Monitor (IMM) has taken the role of the Protestor-in-Chief for reactive revenue requirements filed by PJM generating facilities.

In response to the filings of several facilities seeking Schedule 2 compensation, starting in 2020, the IMM decided to challenge whether facilities connected to the distribution systems of TOs or Distribution Owners (i.e., DERs) actually were entitled to reactive rate revenue under PJM Schedule 2. Before such time, an unknown number of DERs had filed and settled cases involving their reactive revenue requirements. Unsurprisingly, given the all or nothing stakes, the parties could not settle and a hearing was held on the threshold issue of eligibility for compensation, resulting in an Initial Decision in July 2022. FERC reviewed that I.D. and has now issued Opinion No. 583, (Whitetail Solar 3, LLC, et al.) rejecting the compensation claims.

FERC held that to be eligible for compensation under Schedule 2, a facility must be: “(1) under the control of PJM, and (2) operationally capable of providing voltage support to PJM’s transmission facilities such that PJM could rely on that facility to maintain transmission voltages.” FERC elaborated that to qualify, “a generation facility must be operationally capable of providing voltage support to PJM’s transmission facilities such that PJM can rely on that generation facility to maintain transmission voltages.” Simply being capable of injecting VARs at the point of interconnection was deemed insufficient to meet this criterion.

In applying the two-part test above, there was no dispute that the facilities at issue were under PJM operational control as they were market participants. In assessing whether the facilities in question had the operational capability to provide reactive power, FERC found PJM’s views warranted substantial weight. PJM “credibly explained that it is unable to rely on the Facilities for voltage support because they are not directly connected to the transmission system” and “nothing in PJM’s responses suggests that it would be able to rely on the Facilities for voltage support during an emergency.” Other rulings on the various technical bases for finding the facilities unable to meet the operationally capable criterion that were affirmed included: 1) voltage regulation conflicts would arise if PJM were to call on the facilities for voltage support because PJM stated that it was industry practice to direct voltage regulation to the nearest electrical interconnection in order to avoid voltage regulation conflicts, and the nearest interconnections were with distribution buses that it did not control; 2) the electrical distance between the facilities and transmission system may dissipate any voltage support provided by the facilities; and 3) power flow models that showed “some” impact on transmission were insufficient and flawed.

The applicants argued that they were eligible for compensation no matter their specific technical capabilities on numerous grounds that were all rejected. FERC rejected applicants’ reliance on their Interconnection Service Agreements (ISAs) as proof of eligibility, because the ISAs explicitly state that “payments … for reactive power shall be in accordance with Schedule 2.” Similarly, a detrimental reliance argument based on the ISA wording was rejected. FERC ruled that a PJM Technical Manual did not address compensation. FERC refuted an undue discrimination argument based on location on the grounds differing locations meant facilities were not similarly situated. Applicants asserted that a lack of eligibility will discourage DER deployment, but FERC countered that there was no evidence in the record that suggested doing so would adversely affect reliability in PJM or the deployment of renewable generation. FERC noted that MISO, before ending reactive compensation altogether last year, made DERs ineligible in 2013 without adverse impacts. The applicants used Order No. 2222 to claim eligibility, but FERC noted that it only removed barriers for market participation for facilities that are technically capable of providing ancillary services.

Perhaps the most difficult factual issue FERC faced in addressing eligibility is that for many years it routinely accepted settlements filed by DERs compensating them for reactive power under PJM Schedule 2. The applicants naturally pointed this fact out. FERC held that its approval of prior settlements which may have granted reactive power rate schedule treatment in PJM did not constitute approval of, or precedent regarding the issue before it. FERC, however, did not upset existing settlement agreements. Similarly, the applicants located a case where FERC accepted a reactive power rate schedule for a DER in PJM without suspension or hearing. FERC dismissed this argument as well, noting that the “detailed factual record developed at hearing in this proceeding supports a determination different than that reached in the delegated order referenced by Applicants.” Indeed, FERC’s greatest challenge, if a rehearing is submitted and the case appealed, likely will be that it is regulating similarly-situated entities differently, which the D.C. Circuit has found improper on several occasions. But, were an appellate case remanded on such grounds, FERC could take the opportunity to resolve any “discriminatory regulation” problem by issuing a show cause order applicable to all DERs receiving Schedule 2 compensation.

Unquestionably, the opinion raises the question as to whether any DER is entitled to reactive power compensation in PJM (or elsewhere) and whether and what action the IMM or others (i.e., state commissions, consumer advocates, TOs, or FERC itself) may take in light of the decision. There are several dockets in process where the same issue has been raised. In any case, the writing appears to be on the wall and further challenges to FERC policy may result in a more consistent application of this policy.


Continue Reading Oh Dear!  Does <em>Whitetail</em> Spell the End of Reactive Power Rates for DERs in PJM?

We previously indicated that “[t]he March 8, 2022 SEIA v. FERC oral argument on FERC’s PURPA reform rule – Order No. 872 – resulted in a somewhat unexpected lesson on the National Environmental Policy Act (NEPA).” The same can be said of the Ninth Circuit’s opinion on Order No. 872. Although the Final Rule was upheld in its entirety, it also was remanded because FERC violated the NEPA by failing to prepare an environmental assessment (EA) before issuing the Final Rule. The Final Rule will remain in effect during the remand. The EA is rather unlikely to result in changes to the Final Rule, as the court opined the order does not suffer from “fundamental flaws” and it had “no reason to believe that the agency would be unable to cure those deficiencies on remand.”

Although the opinion’s substantive rulings are relatively unremarkable, the opinion’s and concurrences’ discussions of Chevron were perhaps more remarkable and may provide a glimpse of a post-Chevron future. Two judges embraced Chevron deference as the law of the land, with the opinion relying on the premise that the court should “review an agency’s interpretation of a statute under the framework of Chevron.” In concurring with most of the opinion, the third jurist indicated that Chevron deference was unnecessary to uphold the Final Rule.

Under the two-step process of Chevron, a reviewing court first decides if the intent of Congress is unambiguous, or clearly stated, if so, then the inquiry must end. If, the intent of Congress is unclear, or if the statute lacks direct language on a specific point, the court decides whether the agency interpretation is based on a permissible construction of the statute, one that is not arbitrary or capricious or obviously contrary to the statute. The majority relies on Chevron deference because it remains the law of the land. Indeed, two members of the panel chastise their colleague for ignoring Chevron,in premature anticipation of “the Case-That-Must-Not-Be-Named” being overturned by the Supreme Court. Judge Bumatay, a Federalist Society member, is concerned about the future of Chevron and sees no reason to apply the second step of Chevron, as the statute provides FERC ample discretion to adopt the PURPA changes proposed given the statutory text. In any case, Judges Miller and Nguyen also find, in their own concurrence, that “the court’s opinion examines the plain text of the statute and concludes that Congress did not directly address the questions but instead left their resolution to FERC’s discretion.” In sum, even if the Supreme Court were to overturn Chevron, there is every likelihood that the non-NEPA issues would survive further judicial review because Congress provided such broad discretion to FERC in enacting PURPA.

Generally, the opinion found that the Final Rule, as a whole, was not inconsistent with PURPA’s directive that FERC “encourage” the development of QFs. The non-NEPA specific issues that were upheld were: the “Site Rule”; the “Fixed-Rate Rule”; the use of locational marginal energy (LMP) prices as a proxy for avoided cost; and, the reduction to 5 MW in size of the must-purchase rule for utilities requesting relief in certain organized markets. These issues, and the NEPA-based remand, are discussed below.

Consistency with “Encouragement” Requirement. The opinion asserts that petitioners analyzed Order No. 872 incorrectly, by merely arguing that Order No. 872 provides “less support” to QFs than the status quo under the prior PURPA rules. The court pointed out that the appropriate statutory test is for FERC to prescribe “such rules as it determines necessary to encourage” QFs and the statute even directs FERC to “from time to time thereafter revise” those rules. The statute thus gives “FERC broad discretion to evaluate which rules are necessary to encourage QFs and which are not” and the “discretion to reevaluate its rules and alter them in light of experience.” The court found that “PURPA does not require FERC to encourage QFs to the maximum extent possible, regardless of any countervailing interests.” It also held that FERC’s various exercises of discretion were not unreasonable simply because FERC balanced the need to encourage QFs against other competing interests.


Site Rule. In the Final Rule, FERC created a non-rebuttable presumption as to affiliated QFs within one mile of one another being located at the same site for determining size and allowed entities to seek to prove that affiliated QFs located within 1-10 miles of one another are at the same site. (It remains unclear whether the Site Rule impacts PURPA regulations beyond the 80 MW size cap on small power production QFs (Renewable QFs), such as the >1 MW rule for self-certification; the 5 MW and 20 MW purchase mandate limitations; and the FPA rate exemption for >20 MW QFs.) The court found that Congress gave FERC broad discretion to define the meaning of the phrase “located at the same site.” The court dismissed arguments that “site” had to reflect location and physical proximity, noting that the prior PURPA rule also took into account other factors such as fuel type and ownership. As to whether the choice of 10 miles was arbitrary, the court indicated that effectively any number selected would be arbitrary in some sense, but found that where an agency has to choose a number from a range, a court will uphold the number even if other reasonable figures exist. The court ruled that FERC had the authority to change its prior Site Rule policies and that it even mitigated the impacts on QFs relying on the old rules. Claims that the Final Rule was retroactive were readily dismissed on the grounds that a rule is not retroactive merely because it “upsets expectations based in prior law” or “is applied in a case arising from conduct antedating the statute’s enactment.”

Fixed Rate Rule (Energy Rate May Be Variable). In the Final Rule, FERC allowed the avoided energy cost portion of a QF’s contract to vary based on the as-available rate calculated at the time of delivery but continued to require that QFs be given the option to receive avoided capacity costs at fixed rates. Petitioners argued that this aspect of Order No. 872 was discriminatory and arbitrary and capricious. The court explained that the statute did not support this reading because it was so broad that FERC could have imposed a variable energy price for the very start of PURPA. As to the argument that QFs now must accept a variable, uncertain energy rate, whereas utilities are guaranteed the long-term recovery of their costs and a return on investment such that QFs now face financial risks that utilities do not, the court held that Congress never intended to impose traditional ratemaking concepts on QFs. “Order [No.] 872 requires that QFs receive a rate equal to full avoided costs, and that is sufficient to satisfy the nondiscrimination requirement.” The opinion holds that FERC explained its changed policy on energy rates by finding that its prior belief as to under- and over-recovery evening out over time was no longer supported by evidence and that “it is not necessarily the case that overestimations and underestimations of avoided energy costs will balance out.” This finding of regular, routine overestimations not balanced out by underestimations fully justified the change in policy. As to arguments that the change would make financing difficult, the court observed FERC’s finding that the variable energy rate/fixed capacity rate construct is the standard rate structure used throughout the electric industry for power sales agreements. The evidence of a 700 percent increase in independent renewable generation between 2005 and 2018, also supported FERC’s position that QFs would be financeable.

LMP for Energy in Organized Markets. In the Final Rule, FERC provided states the flexibility to use various market prices when calculating a utility’s avoided costs, allowing states to adopt a rebuttable presumption that, for utilities located within certain organized energy markets, the LMP reflects the purchasing utility’s avoided costs. Petitioners’ position, that some utilities procure energy outside auctions and may have avoided costs higher than the LMP, was rejected because a state’s use of LMP as a reasonable proxy for a utility’s avoided costs could be rebutted on a case-by-case basis, if and when a state adopted such approach.

Rebuttable Presumption of Market Access Set to 5 MW for Renewable QFs. In the Final Rule, FERC found that Renewable QFs with a net capacity above 5 MW will be presumed to have nondiscriminatory access to certain markets, such that utilities in those markets can submit filings to be relieved of buying from such Renewable QFs. The former size minimum for mandated purchases was 20 MW for both cogeneration and Renewable QFs. FERC cited changed circumstances since the issuance of Order No. 688 to justify its downward revision of the market-access presumption from 20 MW to 5 MW for Renewable QFs. The court reviewed FERC’s stated basis for that revision – more mature markets, an RTO requirement to allow100 kW resources to participate in markets, and evidence of under 20 MW QFs participating in markets – and found the explanation sufficient.

NEPA. In the Final Rule, FERC determined that Order No. 872 fell within a “categorical exclusion” to NEPA for rules that are “clarifying, corrective, or procedural” in nature and held that any downstream environmental effects were too uncertain and speculative to trigger NEPA review. The court disagreed with FERC that several of its policy changes were corrective, holding: “when an agency adopts broad, transformative, and substantive changes to its regulations, it cannot sidestep NEPA’s requirements by claiming that it was motivated by its desire to better conform to the statute and then applying a ‘corrective’ label. A regulatory change as significant as Order [No.] 872 is not corrective merely because the agency expresses some interest in better statutory compliance.” As to the foreseeability argument, FERC claimed both that its rule did not involve a particular project and that it was impossible to know what the states may choose to do and what impacts the changes would have. The court found that FERC misinterpreted the case law and ruled that an EA is required for a major agency action unless it normally does not have a significant effect on the human environment. The court found that it was “eminently foreseeable that a regulatory change of this magnitude could produce significant environmental effects” because it was a near-certainty that at least some QFs could lose their status under the Site Rule, or that at least some states would eliminate the fixed-rate option for the calculation of energy avoided costs. The court elaborated that “because many QFs rely on renewable power sources, it takes little imagination to see that a reduction in the incentives provided to QFs could, in turn, alter the mix of energy production, shifting production away from renewable production and toward fossil-fuel production.” Thus, the court remanded the Final Rule, requiring FERC to perform an EA.

Importantly, the court did not vacate the Final Rule due to the failure to prepare an EA. The Ninth Circuit test for vacatur weighs the seriousness of the agency’s errors against the disruptive consequences of an interim change that may itself be changed. Although the court found the EA omission serious, courts in the Ninth Circuit ask whether the agency would likely be able to adopt the same rule on remand and the court had no reason to believe that the agency would be unable to cure the deficiencies on remand. As to the disruption that a vacatur would cause, the court ruled it was significant. The court noted that FERC, various states, and regulated parties have all begun to implement the rule in various ways. The court, in an understatement, noted that “several” utilities have already applied for – and received – relief from their mandatory-purchase obligations when dealing with facilities between 5 and 20 MW in size. The “QM” PURPA relief dockets number is already about 50, with most filings by larger, investor-owned utilities.

Judge Bumatay, dissenting on the NEPA issue, found that the petitioners lacked standing to raise the NEPA issue because, despite their claims, the petitioners interests are not distinct from the interest held by the public at large and rest on speculation, or as more colorfully described: “To traverse the gap between FERC’s rule changes and their asserted injury, Petitioners layer conjecture on top of speculation on top of guesswork about how State governments, individual Qualifying Facilities, the broader energy market, and emissions will react to the rule changes. To credit their claim, we must accept that FERC’s new rules will lead to greater fossil-fuel consumption in some unspecified manner, in some unspecified location, to some unspecified degree, by the independent actions of third parties—all leading to an unspecified harm to Petitioners’ members.” As noted above, given many other factors (particularly including state clean energy policies), the tweaks to PURPA made by Order No. 872, likely have had minimal impacts on the country’s fuel mix since they were adopted.

Once the mandate is issued and the case remanded, the court’s prediction that FERC can cure any deficiencies is prescient. Indeed, given the amount of renewable resources in interconnection queues as opposed to fossil resources, the notion that a somewhat “stricter” PURPA would have environmental impacts that merit any further review is highly questionable. Voluntary and state-mandated renewable portfolio standards undermine the notion that the PURPA changes at issue here have, or would play, a meaningful role in the country’s resource mix. Perhaps the strongest argument that FERC’s PURPA rule changes are insignificant in terms of the overall resource mix is the fact that numerous states offer compensation through community solar, net metering, and other programs that allow Renewable QFs to flourish outside of the traditional constraints of PURPA. Actually, the Final Rule’s formal adoption of tiered avoided costs allows states to lawfully impose much higher avoided cost rates than they have historically. In the years since Order No. 872 became effective, the petitioners would be hard pressed to prove that the Final Rule hampered renewable development generally, even as such development likely was slowed to some degree by interconnection queue issues, COVID-19, tariffs, and supply chain issues. With the named Petitioner recently issuing a press release stating “due in part to the strong first quarter numbers and a surge in demand from the Inflation Reduction Act (IRA),” its consulting partner “expects the solar market to triple in size over the next five years, bringing total installed solar capacity to 378 GW by 2028,” proving that the Final Rule is having environmental impacts becomes all the more challenging. The dissent supports this view, relying on record evidence from Montana’s thriving renewables industry, which includes many projects too large for QF status.

Continue Reading FERC’s PURPA Reform Rule Survives Judicial Review Intact, Subject to an Environmental Assessment, as the Majority of the Ninth Circuit Panel Continues to Embrace <em>Chevron</em> Deference

As noted in the most recent blog post, a challenge by Allco Finance Limited (Allco) to the Massachusetts Department of Public Utilities’ (DPU) and the Massachusetts Department of Energy Resources’ (DOER) (Massachusetts Agencies) implementation of Massachusetts’ seven-year old legislation – An Act to Promote Energy Diversity – has no obvious connection to PURPA, yet was submitted as a PURPA Petition for Enforcement (PFE) under PURPA Section 210(h)(2)(B). A Petition for Declaratory Order (PDO) arguably would have been a better, albeit costlier, choice. The few responses to the PFE shed a small amount of light on the relevancy of PURPA issue, but spread a brighter light on the need for state actors to retain FERC counsel before drafting and implementing laws concerning the sale for resale of electricity and transmission of electricity in interstate commerce.

Continue Reading Is PURPA Relevant to Non-PUPRA State Procurement Mandates? Presumably Not, But There Is a Lesson To Be Learned From the Recent Allco Challenge

The easiest means for a state to provide a subsidy to a preferred generation/resource type or class is to mandate purchases from that class at state-mandated rates. The typical reaction of a FERC attorney to such a claim should be, well that approach is simply illegal; states cannot compel utility purchases outside the bounds of PURPA. Indeed, in the last fifteen years, FERC has said so at least twice – when state -mandated purchase programs were challenged by California’s investor owned utilities and the New England Ratepayers Association. FERC resolutely held that mandated purchases were limited to purchases from QFs under PURPA at avoided cost rates. The Supreme Court rejected a (somewhat) less obvious means for states to mandate subsidized wholesale purchases in Hughes v. Talen. But, these cases do not mean that state programs that mandate purchases outside of the PURPA avoided cost construct have been eliminated, even where organized wholesale markets exist. Many such programs still exist, in any number of forms, including net metering programs that pay cash at the end of a time period at above an avoided cost rate and virtually all community solar programs. Most such programs are never challenged, but there is one entity willing to take on some state-mandated purchase programs that fall outside of PURPA, as evidenced by the latest challenge by Allco Finance Limited (Allco), this time to a Massachusetts program.

The Allco petition should be no surprise, as Allco has for over a decade led both the fight against state commissions compelling utilities to pay QF resources above PURPA avoided cost rates and compelling utilities to pay non-QF resources state-mandated rates. Although Allco’s success has been somewhat limited as discussed below, the outsized role Allco has played is not surprising. There are very few utilities willing to challenge a state regulator or legislature that requires the utility to buy from either a QF at above an avoided cost rate or from a non-QF, pursuant to a state-mandated price or process. As a result, some state-mandated programs can morph into a voluntary purchase programs, that are nearly impossible to challenge on legal grounds. One might expect that if a state program were too generous and caused ratepayers to pay unmerited subsidies, that consumer advocates would challenge such programs. However, traditional consumer advocates are often state actors themselves (i.e., independent offices of the state commission, state Attorneys General, etc.), also hesitant to challenge to state action. The result is that Allco has been the primary thorn in the side of state legislatures and commissions, representing neither consumer or utility interests, but the interests of QFs that are ineligible for the programs or are failed bidders in programs.

Continue Reading Mandatory and Not So Mandatory Wholesale Purchases at State-Set Rates:  Allco Leans In

FERC has issued its third and fourth orders on initial compliance attempts with Order No. 2222, covering PJM and ISO-NE. Many of the holdings reflected compliance policies similar to those adopted in the prior NYISO and CAISO orders (summarized previously Part 1, Part 2, Part 3, Part 4). This analysis thus will focus on unique findings, new precedent, and otherwise noteworthy matters.

PJM Compliance Filing Order

Double-Counting. It is remarkable that FERC made two unremarkable findings with regard to net energy metering (NEM) programs under which DER owners are compensated at the full retail rate. First, FERC found that such DERs cannot participate in PJM’s capacity market (largely due to the must-offer energy requirement, but perhaps also recognizing that they would be compensated twice for capacity under such a full retail NEM program). Second, FERC acknowledged that DER owners in full retail NEM programs actually are compensated for ancillary services that they do not even provide and that paying them for ancillary services, assuming they could provide them, would be double counting. The point that DER owners in full retail NEM programs could not possibly earn wholesale compensation in energy, capacity, or ancillary services markets that was not double compensation is a point electric distribution companies (EDCs) have made for years, but this is the first time that FERC has expressed a clear understanding that NEM participants already may be compensated for a large range of products, let alone acknowledged that participants are compensated regardless of whether or not they actually provide such services. Although further clarity will result on compliance, the decision reflects a breakthrough of sorts, as previously FERC refused to explicitly acknowledge that NEM customers in California might be receiving compensation for ancillary services. The fact that the Pennsylvania PUC expressed concern over double counting as to ancillary services in particular perhaps swayed FERC into recognizing the level of compensation offered by some NEM programs. (Of course, it is this level of NEM compensation that largely renders Order No. 2222 meaningless as to some DERs.)

EDC Review. The PJM decision also was notable as to the ferocity with which FERC rejected the notion of giving EDCs more than 60 days to review DER Aggregations, unless the RTO/ISO itself indicates exceptions may be necessary. Although PJM’s pre-registration process was not rejected, the role of the EDC in that process must be reformed and its clear that such process cannot include any EDC review, given PJM’s 60-day EDC review period that is part of the registration process.

Locational Requirements. FERC appeared disbelieving of PJM’s justifications for a single node approach for energy market participation and has sought a change or a better explanation. Given that several other RTOs/ISOs are seeking only single node aggregation, this issue likely will get more attention.

ISO-NE Compliance Filing Order

BTM DERs Metering and Double Counting. The proposed treatment of behind-the-meter (BTM) DERs drew quite a bit of attention from FERC, which found that ISO-NE’s proposal to require measurement of BTM DERs at the retail delivery point, unless the Assigned Meter Reader can accommodate submetering or parallel metering of the DER was not just and reasonable, as it created barriers to entry. Protesters had asserted that measurement at the RDP is a barrier to participation for BTM DERs because it obfuscates actual DER performance for purposes of wholesale market participation and that parallel metering is impractical and costly. ISO-NE argued that metering at the RDP, parallel metering, or submetering combined with reconstitution comprise the universe of metering options of which ISO-NE is currently aware that address double counting. In her concurrence, Commissioner Clements observed that “one comes away with the impression that developing a workable participation framework for behind-the-meter DER is nearly impossible.”

A closer examination of the issue, as relates to customers with on-site BTM DERs and retail load that are not participating in a demand response-only DER Aggregation, reveals that the ISO-NE is assuming that a BTM DER is participating in the wholesale market with its gross, rather than net, production. For example, in its pleadings, the ISO-NE made the point that paying behind-the-meter generator based on its directly submetered output while also billing the customer based on its lower RDP (i.e., retail) meter reading would result in double counting. This fact was the main reason behind ISO-NE’s metering proposal. But there is no double counting at all, if the BTM DER serves its on-site retail load first, and then sells its net output to the DER Aggregator. And, the BTM DER owner likely would ensure that the DER Aggregator can only dispatch the BTM DER to sell its net output. The ISO-NE instead assumes a BTM DER would choose to not serve its on-site retail load before selling any power to the wholesale market, an economically irrational decision unless wholesale market prices reach up the $100s/MWh. That is, BTM DERs are typically installed to reduce on-site load, with net energy (or other services) being sold at wholesale. The notion of a BTM DER selling its gross energy is illogical in nearly every hour of the year. (A BTM DER could be connected to an EDC that mandates a “buy-all, sell-all” structure (an unusual, but not unheard of approach that disallows all netting), but in that case, the proper metering would already exist.)

One question raised by FERC is why did other RTOs/ISOs seem not to have the same issue? There is no evidence that the issue of a BTM DER choosing to sell its gross production would not be a major problem in every other ISO/RTO (again, ignoring demand response BTM DERs). Rather, no other ISO/RTO has assumed the BTM DER is selling gross output, so the issue has not arisen. No one has needed to develop a framework for gross sales because presumably no one would take the economically illogical step of turning over control of their gross energy production to a DER Aggregator, if in nearly all hours, the retail price of electricity exceeds the wholesale price of any market service. Indeed, CAISO has had DER Aggregation for years, but due to net metering, where BTM DERs of all sizes may net, the DER Aggregation program is basically uneconomical for BTM DERs. In NYISO, BTM DERs would presumably sell their net output to the DER Aggregator, avoiding this issue. (And, there is evidence that the New York EDCs expect BTM DERs to choose this net option.)

In sum, the ISO-NE should be able to accommodate BTM DERs that own generators selling only net production, as is typical. If a BTM DER truly intended to sell on a gross basis, the ISO-NE is correct that the metering, billing, and accounting are all quite difficult absent an EDC that already prohibits all netting and meters accordingly. Of particular concern, if FERC believes that BTM DER owners should be able to switch between selling net production at wholesale to selling gross production at wholesale (i.e., selling gross when wholesale prices rise to the $100s-$1000s/MWh), such an approach inevitably would require either resource-intensive manual workarounds and/or expensive (and yet-to-be-developed) metering. Only if the BTM DER bore all such costs, would such approach be equitable to other retail customers. Perhaps ISO-NE explaining to FERC that BTM DERs that are netting on-site retail load can be accommodated could largely solve the perceived problem.

Although the above discussion does not apply to BTM DERs in the form of demand response, Order No. 745 seemingly already addressed the relevant issue. Under Order No. 745, in circumstances in which the net benefits test is satisfied, paying the LMP to BTM DERs participating as demand response resources, without reflecting the savings load realized from not having to purchase electricity, does not reflect a double payment, according to FERC. In contrast, under Order No. 2222, If the BTM DER resource participates as another type of DER (i.e., not as a demand response DER in an aggregation of only demand response DERs), the requirements in Order No. 745 would not apply. In the case of a heterogeneous aggregation, the same problem discussed above admittedly exists because the load served is not entitled to a highly significant benefit of Order No. 745. But, that fact merely raises the issue of why would a demand response DER participate in a heterogeneous DER Aggregation when far more favorable compensation is available through a homogeneous demand response DER Aggregation?

Clements’ Concurrence (ISO-NE)

Clements’ view is that participation of BTM DERs in ISO-NE markets is being completely stymied and reliability is threatened by the issue discussed above – an issue that may very well be non-existent. She mentions Massachusetts and other New England states having aggressive DER goals. One question raised by her dissent is whether Order No. 2222 is actually needed to meet these goals or whether these goals already are being met outside of Order No. 2222. According to the EPA’s State Energy and Environment Guide to Action: Interconnection and Net Metering, issued in 2022, Massachusetts “is a national leader in net metering policy and in the amount of total net metered energy sold back to the utility, which in 2020 was 717 GWh.” According to the EPA, this was “approximately 28 percent of all net metered energy sold back in the United States (EIA 2020).” Moreover, the ISO-NE adopted a new policy allowing small generators to serve as wholesale load reducers by not participating in the wholesale market. Commissioner Clements’ dissent ignores that Order No. 2222 is not the only way to encourage DERs. Indeed, many BTM DERs have state-mandated options that both provide more compensation and eliminate any middleman, and thus are more encouraging of BTM DERs than Order No. 2222. For now.

Christie’s Dissents

Commissioner Christie voted against both orders, despite voting for the CAISO and NYISO compliance orders. (One possible reason that he failed to dissent earlier is that CAISO and NYISO had adopted DER Aggregation voluntarily prior to Order No. 2222 being issued.) Commissioner Christie pointed out in his dissents that the problems and complexities of complying with Order No. 2222 are extreme and the costs enormous. His conclusion in the PJM order is that Order No. 2222 will haunt the RTOs and RERRAs, the reliability of the grid, and the pocketbooks of consumers for a very long time. Although legal/regulatory implementation costs are high, if states continue to use NEM, PURPA programs that ask EDCs to voluntarily pay above avoided cost rates, and other programs that provide more value to energy-producing DERs than the wholesale market, Order No. 2222 will be largely irrelevant. Costs may not be as high as feared if participation is largely non-existent. That said, there is a limit to the degree to which states can use such types of programs before cost shifting renders them unworkable and they are reformed so that DER owners are relegated to earning compensation that more accurately values the services they provide. (As noted, the Pennsylvania PUC quite unabashedly admitted that it pays DERs not only for energy, but for the transmission, capacity, ancillary services and distribution components of retail rates as compensation for the energy produced.) Once state-mandated DER compensation is more accurate, participation in the wholesale market through DER aggregation may become more appealing. But even smaller state subsidies, such as compensating NEM customers for excess energy under a value of solar program, may continue to pay well more than the wholesale market price, less a cut for a DER Aggregator.

One leaves the newest compliance orders with the impression that a fulsome understanding of the direct connections between state DER programs (including NEM), Order No. 745 demand response aggregation programs, and Order No. 2222 aggregations and how, whether, or why a DER may choose among such options does not yet exist. Given that there may be as many different such connections as there are states with at least one ISO/RTO member, renders obtaining such an understanding difficult. Such direct connection also may result in retail customers paying Order No. 2222 implementation costs when Order No. 2222 DER Aggregations will not be an option that is economically logical for DER owners.

Recently, the D.C. Circuit upheld FERC’s decision granting Broadview Solar’s application to become a QF in SEIA v. FERC. In doing so, the appeals court solidified FERC’s “send-out” capacity approach for determining QF status. The underlying case, Broadview, has been the subject of several prior blog posts, as the underlying FERC decisions reflect just how deeply political PURPA, and its application, have become. The decision in this case was quite likely to turn, in the first instance, on three jurists’ views on agency deference under Chevron, a judicial doctrine that has become highly politicized because of varying views of the role of the administrative state. The panel consisted of Circuit Judges Sentelle (a Reagan appointee, extraordinarily well versed in FERC, who has drafted or signed onto many important orders upholding FERC opinions based on Chevron deference, but who will rein in FERC when the agency exceeds its statutory bounds), Pillard (an Obama appointee), and Walker (a Trump appointee whose disdain for Chevron deference was on full display here). Walker’s claim that “[o]n the D.C. Circuit, Chevron maximalism is alive and well,” historically has been accurate, and only a rehearing en banc would indicate whether that tide has turned. There is no question the tide has turned at the United States Supreme Court. As discussed herein, it actually is shameful that this proceeding could result in a significant decision on Chevron deference, as it is Congress’ responsibility to address the many issues presented by PURPA, such as what is meant by “power production capacity,” before the law turns forty-five later this year.

The primary issue on appeal was whether the measure of relevant capacity under the statutory definition of small power production facility (limiting such QFs to 80 MW of power production capacity) should be based on how much power could be sent to the transmission system.  In finding that Broadview merited QF status, FERC took into account all of its components working together, not just the maximum capacity of one subcomponent, focusing on grid-usable AC power. Using the Chevron framework, the D.C. Circuit (1) agreed with FERC that the measure of “power production capacity” is ambiguous under PURPA Section 210; and (2) determined that FERC’s focus on grid-usable AC power was reasonable because it aligned with PURPA’s structure and purpose. The opinion explained that focusing on net output (rather than denying facilities QF status because a subcomponent exceeds 80 MW) advanced PURPA’s goal of promoting small power production facilities and the use of alternative energy sources. Finally, the court concluded that FERC’s interpretation aligned with legislative history regarding the meaning of power production capacity.

This opinion would have been wholly unremarkable, but for the first Broadview FERC order, which rejected forty years of FERC precedent and reflected a more textualist view of the statute. In his dissent, Circuit Judge Walker reached the same substantive outcome as was adopted in the first FERC order, that Broadview was too large to be a QF. He explained that PURPA Section 210’s mandatory purchase requirement is an extraordinary measure, which can force utilities to purchase above-market or unnecessary power and pass on costs to consumers. He noted that the broader the definition, “the greater the number of power plants that get special regulatory treatment.” Next, Judge Walker focused on how narrowly Chevron deference should be applied, explaining that courts must try every tool of statutory construction before declaring the text ambiguous and proceeding to agency deference. He agreed with Justice Kavanaugh that the court will almost always reach a conclusion about the best interpretation of the statute, resolving any ambiguity. Walker then focused on the fact that Broadview’s facility can produce 80 MW for its inverters (to sell), while it simultaneously produces 50 MW for its battery to store, such that it is too large to be a small power production facility.

This case can be appealed, or a rehearing en banc may be requested, and thus its ultimate conclusion is unknown. Moreover, theD.C. Circuit is unlikely to be the last word on power production capacity because the D.C. Circuit likely will not be the first choice of another utility aggrieved by identical facts. Putting aside the threshold question of whether PURPA is ambiguous and Chevron has relevance to any judicial analysis of the issue, Congress can and should dictate the future of PURPA policy. The mere existence of this the case reflects a failure by Congress to reconsider innumerable aspects of PURPA, but for one significant change in the Energy Policy Act of 2005. Indeed, the majority’s focus on Congressional intent and encouraging renewables up to 80 MW in size is rather ironic given that in 2005 Congress passed a law such that for a huge swath of the country, small power production QFs now must be under 20 MW or 5 MW to obtain a PURPA contract from a utility. And, the relevant industry changes that have occurred between 2005 and 2023 arguably dwarf the industry changes that occurred between 1978 and 2005. In the nearly two decades since the Energy Policy Act of 2005 somewhat limited PURPA’s reach, profound changes have occurred in the electric industry with regard to renewables. Such changes include reductions in the cost of renewable power, technological advances in storage, and the widespread adoption of mandatory and voluntary renewable mandates.

It is actually astounding that a law driven by an industry largely fueled by oil and coal, drafted in an era when renewable energy was in a larval stage and the storage industry, i.e., renting large lockers to store furniture, cars, etc., was just starting to hit its stride, oops!, i.e., storing energy for later use as a substitute for generating plants did not even exist, is now causing judicial posturing over an issue that Congress could readily address with very minor legislative tweaks. Resolution of this issue is best performed by Congress.

Who will be paying for the impacts of on both distribution and transmission systems of widespread DER penetration, whether it is in the form of DER Aggregations under Order No. 2222, state-jurisdictional net energy metering (NEM), or stand-alone DERs (often PURPA facilities)? And, who will decide who bears such costs – FERC or state commissions? These are questions that need to be answered over the coming years. Likely, the answers to these questions will be inconsistent across the states and disputes regarding cost allocation as well as jurisdictional could occur. Although the cost allocation disputes over NEM have been increasing in number and intensity, they have remained largely within individual states. With DER Aggregations, non-NEM DER participations, and Reliability Standards involving invertor-based DERs, such disputes should involve more, and more complex, issues.

The fact FERC and the states share some jurisdiction over distribution service, as well as jurisdiction over DER programs varying based on the programs’ characteristics, both create a bit of a jurisdictional quagmire as to who determines how costs imposed on utility distribution companies (UDCs) and transmissin owners/providers will be allocated. Although some utilities are taking matters into their own hands, seeking to recover significant distribution system modernization costs in retail rate cases, how and whether DERs participating in FERC-jurisdictional programs, such as DER Aggregation or FERC-jurisdictional sales, will contribute to the recovery of costs that their market participation causes remains unclear. Similarly, whether and how IBR-DERs, and most DERs are IBR-DERs, will bear costs of transmission system impacts of their aggregate adoption is likewise murky.

FERC has been largely silent on who even has jurisdiction over the cost of analyzing the reliability impacts of DER Aggregations under Order No. 2222 on the distribution system of a UDC. Impacts of DER Aggregations on transmission systems may be rare, but raise similar questions. One of FERC’s most recent NOPRs, Invertor-Based DERs and Transmission System Reliability, implicates cost questions, but never answers them. For example, will all transmission customers, or all distribution customers, bear the costs of NERC compliance associated with IBR-DERs, or will it depend on who is incurring such costs – UDCs or transmission owner/providers?

This article explores a few of the areas where many answers surrounding cost and jurisdiction seem lacking.

Order No. 2222 and Distribution System Reliability Costs

In Order No. 2222, FERC shifted jurisdiction over all interconnection of DERs in Aggregations (other than those DERs who were interconnected under FERC jurisdiction and decided to stay that way) to the states. Thus, the interconnection of individual DERs would be subject to either existing, new, or modified UDC interconnection procedures, some of which procedures are state-regulated. A sampling of such state-regulated procedures, often first drafted in the context of PURPA implementation, indicate that it is typical to allow the utility to charge for needed studies and analysis, as well as interconnection costs, with some variation, depending on the nature and size of the DER and the DER’s business plans.

But, Order No. 2222 also permits “incremental” analysis of DERs that are aggregating. Under Order No. 2222, RTOs/ISOs must coordinate with UDCs to develop a distribution utility review process that includes criteria by which the UDCs would determine whether the participation of each proposed DER in an Aggregation will pose significant risks to the reliable and safe operation of the distribution system. Despite this mandate, FERC has now found in several Order No. 2222 compliance orders in which UDCs must develop such criteria for DER Aggregations, it is unclear who has jurisdiction over this “second” reliability analysis and the costs associated with applying it to DER Aggregations where the UDC is FERC-jurisdictional. (One of Order No. 2222’s very few mentions of how costs imposed by DER Aggregations should be allocated related to a finding that it may also be appropriate, on a case-by-case basis, for UDCs to assess a wholesale distribution charge on DER Aggregators and this process could be a FERC-jurisdictional vehicle for the analysis.) But, it remains somewhat unclear who has jurisdiction over the costs associated with DER Aggregation reliability analysis and any costs to upgrade distribution systems due to DER Aggregations.

Since DER Aggregation already was permissible in CAISO and NYISO prior to Order No. 2222, UDCs there might provide answers, but if any UDC DER Aggregation reliability review processes have been established by such utilities, they are not readily locatable. Most state commissions have not even started to consider the issue of studying or analyzing DER Aggregations, whether inside the state interconnection process context or in a broader context. A few states – Missouri, California, and Indiana – have opened rulemakings or passed laws that will examine Order No. 2222 potential impacts, but progress is slow. Indeed, some state commissions have remained focused on other DER issues. For example, in September 2021, the Massachusetts commission decided to not investigate investments driven primarily by future compliance with FERC Order 2222 in a proceeding involving UDC Grid Modernization Plans. 

Here are just a few cost allocation/recovery issues that could arise:

  • Does a FERC-jurisdictional UDC need FERC permission to collect fees for a FERC Aggregation reliability analysis, if the analysis is outside the state interconnection context?
  • Who will bear the costs UDCs may incur to modernize or enhance their distribution grids to accommodate Order No. 2222, if Order No. 2222, as opposed to state NEM programs, is the cause of modernization need?
  • If states allocate grid modernization costs to DER-owners selling at wholesale and DER Aggregators, how and who will perform such allocation?

One interesting note on this topic, the Kentucky PSC actually found recently in a NEM proceeding that participation in wholesale power markets by DERAs is likely to increase the cost to serve customer-generators and that NEM rules may need to discourage participation in DER Aggregations.

Order No. 2222 and RTO/ISO Transmission Reliability Costs

In Order No. 2222, FERC says very little about the DER Aggregation application process, other than the fact it would involve coordination with the relevant UDC and coordination with the retail regulatory authority (RRERA). The RTO/ISO was tasked with certain activities regarding reliability, although the issue of the impact of DER Aggregations on transmission system reliability was largely overlooked. FERC found that coordination between RTOs/ISOs and UDCs should ensure that RTOs/ISOs have the information that they need to study the impact of DER Aggregations on the transmission system. There were no specific processes mandated with regard to how or whether an RTO/ISO should study or review the impacts of a DER aggregation on its transmission system for reliability purposes.

The Order No. 2222 compliance filings generally include application processes and procedures, but with little focus on any ISO/RTO reliability analysis or payments for the same by a DER Aggregator (DERA). RTOs/ISO seemingly have imposed no fees associated with DERA registration (beyond existing registration fees for market participants), or explained what would happen if a UDC identified a transmission system reliability issue that would cause the need for an upgrade.

Perhaps DER Aggregations, in states where they do form, will rarely if ever cause transmission system costs, such that this question will rarely arise. But if an aggregation does have transmission cost implications, who should seek cost recovery and through which regulator, remains unclear, particularly if the impact is found by the UDC. It is possible that any transmission system cost impacts will be identified in the state-jurisdictional interconnection process, rendering the ISO/RTO an “Affected System.” State interconnection processes thus should address the need for Affected System upgrades on the interconnected transmission system.

Invertor-Based DERs and Transmission System Reliability Costs

FERC has issued a NOPR on gaps in NERC’s Reliability Standards relating to IBRs, which NOPR is focused, in part, on IBRs connected at the distribution level. FERC preliminarily found that the existing NERC Reliability Standards may not provide Bulk-Power System planners or operators with the tools necessary to plan because IBR-DERs, when acting in the aggregate, can have a material impact on the reliable operation of the Bulk-Power System. According to FERC, the Reliability Standards should ensure that validated planning and operational studies assess the reliability impacts on Bulk-Power System performance by IBR-DERs in the aggregate. FERC expresses concern in the NOPR about modeling, such as whether UDCs are communicating to planners and operators concerning IBR-DERs in the aggregate for modeling purposes, including settings, configurations, and ratings. FERC notes that the existing Reliability Standards do not require the provision of data that represents IBR-DERs in the aggregate, at a sufficient level of fidelity for planners and operators to accurately plan, operate, and analyze disturbances on the Bulk-Power System. 

Proposed solutions impose new requirements on UDCs such as providing validated models of IBR-DERs in the aggregate to planning coordinators for interconnection-wide planning and operational models. Another proposal is to require UDCs that have IBR-DERs to provide to planning coordinators, transmission planners, reliability coordinators, transmission operators, and balancing authorities models accurately represent the dynamic performance of IBR-DER facilities in the aggregate, including momentary cessation and/or tripping, including all ride-through behavior (e.g., IBR-DERs in aggregate modeled by interconnection requirements performance to represent different steady-state and dynamic behavior).

What is missing from the NOPR is any discussion of costs, cost allocation, and jurisdiction. In fact, the words “cost” and “expense” are not mentioned at all. For example, what if the UDC is not affiliated with any Transmission Owner (e.g., Consumers Energy, DTE, etc.) and it is incurring costs under the new standards, is such a UDC allocating compliance costs only to distribution customers, largely under state jurisdictional rates? If the Transmission Owner in such a scenario is having to expend money to address an unaffiliated UDC’s IBR-DERs transmission-system impacts, it would seem FERC has jurisdiction over who pays those costs in the first instance – but, that does not answer the question of who should pay such costs. Another important question is what if NEM tariffs prevent allocation of costs to the very IBR-DERs owners causing the need to collect and model data; is it fair to require non-participating retail customers to bear such costs? Can IBR-DERs in NEM programs and other IBR-DERs be treated differently as to cost allocation? Questions abound.

The scope of IBR-DERs with which FERC is concerned also is not mentioned in the NOPR, which scope could have a significant impact on cost allocation. Most importantly, an IBR connected to the distribution system, i.e., an IBR-DER, could include behind-the-retail-meter (BTM) IBR-DERs, which has profound consequences for cost allocation, particularly where those customers with BTM IBR-DERs are largely NEM residential customers. If FERC adopts Reliability Standards that requires UDCs to expend millions of dollars to implement the NOPR and to address the existence of IBR-DERs, it is rather important to understand which IBR-DERs’ data must be aggregated, if a UDC and Transmission Owner are going to allocate costs on a causation basis, rather than simply roll in the costs of such expenses to all customers. For example, a cost-allocation line could be drawn between IBR-DERs that do and no not participate in wholesale markets. Such a cost allocation line would be appropriate if FERC is only asking for data in the NOPR on IBR-DERs that participate in wholesale markets. That said, such a set of data may be meaningless from a reliability standpoint if the overwhelming majority of impacts on the Bulk Power System are actually related to NEM customers with IBR-DERs. If IBR-DERs are selling under PURPA, that law presents another complex jurisdictional situation regarding to whom and by whom costs could be allocated. If FERC simply expects all customers that pay for distribution or transmission service to bear IBR-DER-related Reliability Standard compliance costs – which is a possibility – the link to cost causation is broken.

In sum, clarity does not exist at this time as to many interesting and complex questions involving various DER programs.

Fifth and final post on the Order No. 2222 compliance filings issued on June 17, 2022: “CAISO 2222 Order” and the “NYISO 2222 Order.” The post covers the topics: Modifications to List of Resources in Aggregation; Market Participation Agreements; and Effective Date.

Topic 10: Modifications to List of DERs in Aggregation

In Order No. 2222, FERC required each RTO/ISO to establish market rules that address modifications to the list of DERs in a DER Aggregation. The Commission ruled that any modification re-triggers the Distribution Utility (DU) review process, although that review could be abbreviated. FERC urged abbreviated procedures especially for an exiting DER.

This issue was not discussed as to the CAISO.

The NYISO was ordered to correct wording that allowed DU review of only incremental modifications to an Aggregation, rather than to review any modification; this correction may just be a matter of semantics.

Topic 11: Market Participation Agreements

Each RTO/ISO must establish market rules that address market participation agreements for DER Aggregators that defines the DER Aggregator’s role and responsibilities and its relationship with the RTO/ISO. The Commission stated that this market participation agreement must include an attestation that the DER Aggregation is compliant with the tariffs and operating procedures of the DU and the rules and regulations of any retail regulator (RERRA). The market participation agreements could not limit the business models under which DER Aggregators can operate.

This issue was not discussed as to the CAISO.

The NYISO’s use of its existing Service Agreement under the Services Tariff was accepted with a fix to the attestation. NYISO’s proposed attestation required the Aggregator to attest that the DU and RERRA have authorized the individual facilities and Aggregation to participate in the wholesale markets. FERC found that the attestation should instead address compliance with the tariffs and operating procedures of the DU and rules and regulations of any RERRA.

Topic 12: Effective Date

FERC required each RTO/ISO to propose a reasonable implementation date, together with adequate support explaining how the proposal is appropriately tailored for its region and implements Order No. 2222 in a timely manner.

CAISO requested an effective date no later than November 1, 2022 for the proposed Tariff sections that pertain to heterogeneous DER Aggregations, and for all other proposed Tariff revisions, CAISO requested an effective date contemporaneous with the Commission’s approval of its Tariff revisions. FERC accepted this proposal.

The NYISO’s proposed implementation timeline in the fourth quarter of 2022 also complied with Order No. 2222. NYISO also had to file a proposed effective date by which it will allow DERs in heterogeneous Aggregations to provide all of the ancillary services that they are technically capable of providing through aggregation. This proposal was accepted

The effective date issue was not at all controversial as to these ISOs because they were immediate/relatively soon, which was expected given their existing Aggregation programs. Other RTO/ISO proposed effective dates, i.e., MISO in particular, already have proven far more controversial.