On November 30, 2022, in Docket No. ER23-523, the Midcontinent Independent System Operator, Inc. (MISO), on behalf of the MISO Transmission Owners (MISO TO),[1] submitted proposed revisions to Schedule 2, Reactive Supply and Voltage Control from Generation or Other Sources Service of its Open Access Transmission, Energy and Operating Reserve Markets Tariff (Tariff).  The MISO TOs proposed to eliminate all charges under Schedule 2 for the provision of reactive power within the standard power factor range (Reactive Service) from MISO TOs’ own and affiliated generation resources.[2]  Based on the Commission’s “comparability standard,” MISO TOs stated that their proposal also terminates the obligation under Schedule 2 to pay unaffiliated generation resources in MISO for reactive power within the standard power factor range.  FERC accepted MISO TOs’ proposed Schedule 2 revisions, effective December 1, 2022.  This means that the $220 million being paid in MISO to generators for the provision of reactive power ends December 1, 2022.  

Many comments were filed in this docket, particularly from generators opposing the elimination of reactive power compensation.  Notwithstanding, FERC found that the revisions are just and reasonable and not unduly discriminatory or preferential.  As FERC articulated in Order No. 2003, “the Interconnection Customer should not be compensated for reactive power when operating its Generating Facility within the established power factor range, since it is only meeting its obligation.”  In Order No. 2003-A, FERC clarified, however, that “if the Transmission Provider pays its own or its affiliated generators for reactive power within the established range, it must also pay the Interconnection Customer.”  Consistent with Order No. 2003 and 2003-A, where a transmission provider does not separately compensate its own or affiliated generators for reactive power service within the standard power factor range, it is not required to separately compensate non-affiliated generators for reactive power service within the standard power factor range.  Comparability entitles a generator to compensation for providing reactive power within the standard power factor range “if, and only if, the [t]ransmission [p]rovider pays its own or affiliated generators for reactive power within the [standard power factor range].”  FERC found that MISO TOs’ proposed Schedule 2 revisions to eliminate compensation for its own and affiliated generation resources and unaffiliated generation resources and the associated charges to transmission customers is permitted under, and consistent with, Order Nos. 2003 and 2003-A.  Additionally, FERC stated that Order Nos. 2003 and 2003-A do not mandate that once a transmission provider compensates its own or affiliated generators, it may never discontinue such compensation and must, as a result, always compensate unaffiliated generators.  Rather, FERC precedent allows transmission providers to eliminate compensation for reactive power within the standard power factor range for all generators, regardless of whether the generator is owned by or otherwise affiliated with a transmission owner or is independent.  FERC found protests that challenge these well-established policies to be collateral attacks on these earlier determinations.

Commissioner Danly dissented, stating that, notwithstanding the increased rates and the administrative burden of the present compensation approach, FERC cannot simply accept the MISO TOs’ proposal unless they meet their section 205 burden that the proposed rate—in this case, the elimination of reactive power compensation—is just and reasonable based on substantial evidence in the record.  He went on to state that the MISO TOs did not offer any evidence of the effects of eliminating the $220 million annual reactive power revenue requirement from the MISO tariff, and what is clear on the record is that separate reactive power compensation has been available in MISO for several years, and parties have taken this into account in their financings, bilateral contracting, power purchase agreements, and other arrangements.
​
Commissioner Clements stated in a concurring statement that she encourages stakeholders in MISO to consider more effective alternatives to cost-based reactive power compensation as services should be appropriately compensated for the benefits they provide, and reactive power plays an important reliability function.  She remains open to the possibilities of other reactive power compensation options, such as market solutions or compensation models that are based on the performance of the generators in providing reactive power when called upon, or that incentivize reactive power generation to be located where additional reactive supply is most needed from a reliability perspective.


[1] MISO TOs include:  Ameren Services Company, as agent for Union Electric Company, Ameren Illinois Company, and Ameren Transmission Company of Illinois; Arkansas Electric Cooperative Corporation; City Water, Light & Power (Springfield, IL); Cooperative Energy; Dairyland Power Cooperative; East Texas Electric Cooperative; Entergy Arkansas, LLC; Entergy Louisiana, LLC; Entergy Mississippi, LLC; Entergy Texas, Inc.; Great River Energy; Indianapolis Power & Light Company; Lafayette Utilities System; MidAmerican Energy Company; Minnesota Power (and its subsidiary Superior Water, L&P); Missouri River Energy Services; Montana-Dakota Utilities Co.; Northern States Power Company, a Minnesota corporation, and Northern States Power Company, a Wisconsin corporation, subsidiaries of Xcel Energy Inc.; Northwestern Wisconsin Electric Company; Otter Tail Power Company; Prairie Power, Inc.; Southern Indiana Gas & Electric Company; and Southern Minnesota Municipal Power Agency.

[2] The phrase “standard power factor range” refers to the power factor range required for interconnection and set forth in the interconnecting generator’s generator interconnection agreement (GIA).  MISO’s pro forma GIA prescribes a power factor range of 0.95 leading to 0.95 lagging.  This range is also sometimes referred to as the “deadband.” 

On February 24, 2022, the Office of the Ohio Consumers’ Counsel (OCC) filed a complaint (Complaint) against American Electric Power Service Corporation (AEPSC), American Transmission Systems, Inc. (ATSI), and Duke Energy Ohio (Duke) (together, Ohio TO) alleging that they are ineligible for a 50-basis point adder to the authorized return on equity (ROE) for participation in a Transmission Organization (RTO Adder).  This filing occurred many months after a FERC Order finding that The Dayton Power and Light Company did not qualify for an RTO Adder as under Ohio law participation in a transmission organization was not voluntary but required. 
  
FERC found that the Office of the Ohio Consumer Counsel (OCC) has shown that the rates for Ohio Power and AEP Ohio Transmission (AEP companies) are unjust and unreasonable because the Commission specifically granted them an RTO Adder under section 219 and that their continued participation in a Transmission Organization is mandatory in Ohio.  FERC also found that OCC has not met its burden of showing the rates for Duke and ATSI in Ohio are unjust and unreasonable as the Commission did not specifically grant them an RTO Adder under section 219, and their rates were instead the products of comprehensive settlements.  FERC ordered AEP to make a compliance filing, within 30 days of the date of this order and to remove the RTO Adder from their rates effective February 24, 2022.   Commissioner Danly dissented from the order, stating that the Federal Power Act does not limit incentives to only those utilities that “voluntarily” join a transmission organization and that FERC improperly added this non-statutory requirement in Order No. 679 and had no authority to do so then or now.  In his concurring statement, Commissioner Christie refers to the RTO Adder as “FERC candy” and states that in April 2021, he voted that the RTO Adder would be in effect for a transmission for three years then disappear.  The rulemaking considering transmission incentives, including the RTO Adder, is ongoing at FERC. 

​In Docket No. EL22-31, FERC denied on rehearing the Northern Maine Independent System Administrator’s request for reciprocal elimination of Through and Out Rates between it and ISO-NE.  Though FERC requires elimination of seams, including rate pancaking, within an RTO, such policy is to encourage, not require, reciprocal waivers of access charges between RTOs if such waivers can be accomplished in a manner that is reasonable in terms of cost recovery, cost shifting, efficiency, and discrimination.  Furthermore, where a particular RTO application proposes to rely on an “effective scope” in lieu of a larger geographical control area to satisfy Order No. 2000’s scope requirement, the Commission requires the applicant to show that the integration of the RTO’s markets with those of its neighbors would serve as the functional equivalent of a larger RTO.    ISO-NE’s RTO application was one that relied on an “effective scope” to satisfy the Commission’s scope and regional configuration requirement.  However, NMISA misinterpreted FERC’s inter-RTO rate pancaking policy as a mandate and misinterpreted the condition placed on ISO-NE’s RTO status due to its reliance on an “effective scope” to meet Order No. 2000’s scope requirement.  In granting ISO-NE RTO status, the Commission conditioned its approval upon ISO-NE reducing seams with NYISO specifically.  While the parties that proposed the formation of ISO-NE as an RTO also committed to attempt to reduce seams more broadly, mentioning other neighboring control areas, FERC did not condition ISO-NE’s RTO status on that further commitment.  Furthermore, the fact that the parties that formed ISO-NE made that further commitment does not equate to a condition on ISO-NE’s RTO status, nor does it transform the Commission’s policy to only require seams management agreements when an RTO proposal relies on an “effective scope” to satisfy Order No. 2000’s scope requirement into a universal requirement for seams management agreements.  FERC found that the relationship between NMISA and ISO-NE is not the same as that between the NYISO and ISO-NE.  NMISA has not sought or been granted RTO status as defined in Order No. 2000.  Thus, the rate pancaking policy, by its express terms, does not encompass NMISA because it only encourages reciprocal waiver of access charges between RTOs.  In reaching its decision to deny NMISA’s request, FERC considered whether NMISA was similarly situated with NYISO, and found that it was not.  This finding was based on the following factors:  1) NMISA has not negotiated a comprehensive seams management agreement with ISO-NE like NYISO did, 2) NMISA is not directly and substantially interconnected with ISO-NE like NYISO is, and 3) NMISA does not operate organized energy and ancillary service markets like ISO-NE’s like NYISO does.  The Commission pointed out that “[t]he principal purpose of the comprehensive seams management agreement between ISO-NE and NYISO is to address the high degree of interaction between their similar organized markets.”  A review of NMISA’s tariff document shows that NMISA’s function related to energy and ancillary services is primarily to purchase such energy and ancillary services from New Brunswick (under a specific New Brunswick tariff) or from third-party sellers (under bilaterally negotiated contracts) on behalf of the Competitive Electricity Providers (CEP) that serve retail load in the NMISA area of Maine.  Finally, the fact that NMISA and ISO-NE are electrically remote from each other (i.e., are not directly interconnected) means that the need for information sharing on such matters as real-time transmission congestion is markedly reduced between NMISA and ISO-NE compared to ISO-NE and NYISO.  

​In Docket No. ER22-1395, Public Service of New Mexico (PNM) filed two, late-filed, non-conforming, long-term firm point-to-point transmission service agreements (TSAs) with PacifiCorp and Tri-State Generation & Transmission Association, Inc. (Tri-State) under PNM’s Open Access Transmission Tariff (Tariff), with service commencing on December 1, 2005, and January 1, 2008, respectively.  PNM stated that it discovered the non-conforming TSAs in the process of performing a comprehensive review of its TSAs and internal processes for identifying and filing jurisdictional agreements with the Commission.  PNM noted that it was filing a report of the late-filed agreements to the Commission’s Office of Enforcement.  On the same date, in Docket No. ER22-1396-000, PNM filed 13 non-conforming, long-term, firm, point-to-point TSAs with several customers, entered into on various dates from July 1, 2005, to June 1, 2019.
 
FERC’s initial orders in these two cases (PNM I and PNM II) directed PNM to refund the time-value of monies actually collected for the time period during which the rates were charged without Commission authorization.  The orders directed PNM to make time-value refunds within 30 days for the TSAs, and to file a refund report within 30 days thereafter, and make a showing in the refund report, to the extent that time-value refunds would result in a loss.  On June 16, 2022, PNM requested rehearing, arguing that the time-value refunds, which it claimed would require it to pay its customers more than $7 million as a result of PNM I and in excess of $28 million as a result of PNM II, are unlawful, substantial and punitive.
 
On rehearing, FERC continued to find that refunds are required for PNM I.  FERC stated that its policy and precedent requiring refunds for late-filed agreements is well settled.  FERC stated that time-value refunds serve two purposes, in connection with the Commission’s statutory obligations:  (1) to protect customers, including against unduly preferential treatment, and (2) to incentivize public utilities to comply with the filing requirements of FPA section 205.
 
As for PNM II, FERC continued to find that PNM was under an obligation to file the 13 TSAs.  However, they clarified in the order on rehearing that, even though PNM was required to file the TSAs, based upon the circumstances in the case, FERC relieved PNM of its obligation to provide time-value refunds with respect to the 13 TSAs.   Section 35.1(g) of the Commission’s regulations requires that …”[a]ny individually executed service agreement for transmission, cost-based power sales, or other generally applicable services that deviates in any material respect from the applicable form of service agreement contained in the public utility’s tariff and all unexecuted agreements under which service will commence at the request of the customer, are subject to the filing requirements of this part.”  Here, as PNM’s 13 TSAs deviate from the standard language of its pro forma TSA, the TSAs are necessarily non-conforming.  In Order No. 2001, the Commission stated that “if an agreement does not precisely match the applicable standard form of service agreement . . . it is necessarily nonconforming and must be filed individually for Commission approval.”  Notwithstanding, FERC relieved PNM of its financial obligations as PNM had been maintaining a log detailing when it waived the deposit requirement of contracts (the issue with the 13 TSAs).  FERC stated that while the requirement to maintain a log arguably provides an alternative means for Commission oversight of PNM’s exercise of discretion under that Tariff provision, FERC concludes that the requirement, in and of itself, did not relieve PNM of its filing obligations under section 205 of the FPA given that the agreements are, as discussed above, nonconforming.  Nonetheless, as PNM maintained a log to record waiver of the applicant deposit and that log was available for the Commission to review, there may have been confusion as to whether the agreements also needed to be filed to ensure Commission oversight.  

​This case involves the base ROE for transmission owners in MISO.  A group of customers thought the base ROE provided by FERC was too generous and they asked FERC in 2013 and in 2015 in Section 206 proceedings to reduce that aspect of MISO’s rates. FERC did. In the process, FERC completely overhauled its approach to setting an appropriate ROE. Both the customers and transmission owners challenged several aspects of the FERC proceedings as unlawful or arbitrary and capricious. The Court agrees with the customers that FERC’s development of the base ROE methodology was arbitrary and capricious, so the Court vacated FERC’s base ROE orders and remanded for further proceedings.
 
The customers challenge FERC’s new base ROE methodology on five grounds. First, they argue that FERC should not have altered its previous approach to balancing long-term and short-term growth rates in the discounted-cash-flow model (Model 1). Second, they challenge three aspects of FERC’s approach to the capital-asset model (Model 2). Third, they argue that FERC’s creation of presumptively just and reasonable ranges at step one of the Section 206 analysis was arbitrary and capricious. Fourth, they argue that FERC should have set the new Return based on the median of the zone of reasonableness rather than the midpoint. And fifth, they challenge FERC’s decision to resuscitate the risk-premium model (Model 4) in its second rehearing order shortly after interring the model in its first rehearing order.  The Court found the first four of those arguments unpersuasive, but it agreed with the customers’ final argument. FERC failed to offer a reasoned explanation for its decision to reintroduce the risk-premium model (Model 4) after initially, and forcefully, rejecting it.  Because FERC adopted that significant portion of its model in an arbitrary and capricious fashion, the new base ROE produced by that model cannot stand. The Court therefore vacated FERC’s MISO base ROE orders to reopen the proceedings. 

​In an Order dated July 26, 2022, in Docket No. ER22-1955, FERC accepted changes to MISO’s competitive transmission project process to assign the development of a transmission project where the costs are 80% or more related to the upgrade portion of a project to the incumbent transmission owner.  Four of the commissioners attach a concurring statement that expresses their concern that existing processes may not adequately protect consumers with regard to the selection and construction of many transmission projects and that this Order has the negative consequence of expanding the scope of projects for which the transmission owner has less incentive to reduce cost and maximize benefits to the greatest extent possible.  They go on to state that, in response to the Commission’s Advanced Notice of Proposed Rulemaking on regional transmission planning, cost allocation, and generator interconnection, many commenters including the National Association of Regulatory Utility Commissioners (NARUC), urged the Commission to apply greater scrutiny to the costs of transmission projects.  Specifically, NARUC “recommends that the Commission explore whether there is some limit at which the presumption of prudence no longer applies and ratepayers would benefit from an automatic review of the prudence of an expenditure.”  Other commenters suggested a variety of approaches to limiting project costs, such as enhanced transparency, or utilizing an independent transmission monitor to assist the Commission in implementing appropriate cost caps.  The need for the Commission to apply scrutiny is particularly acute for projects that are subject neither to competition at the wholesale level, nor to cost review pursuant to state jurisdictional proceedings.  Accordingly, we note that a lack of competition at the regional level for an increased number of projects selected as part of its transmission planning process, coupled with a less than robust level of scrutiny of such projects at the state level, may require greater cost scrutiny of those projects by the Commission.  The Commission is holding a technical conference on October 6, 2022, to examine cost management of transmission investments.  We hope for robust participation in this conference and urge stakeholders to provide the Commission with detailed information regarding these issues so as to inform any subsequent action the Commission may take.  In particular, we urge commenters to provide a detailed picture of the extent of cost review that currently exists at the state level for different types of transmission projects, including regionally selected projects not subject to competition such as MISO’s “upgrade” projects described in this order, as well as local projects constructed by transmission owners.

On March 10, 2022, Maine Power Link, LLC (MPL) submitted a request for Commission authorization to charge negotiated rates for transmission rights on its proposed transmission project (Project) if the Maine Public Utilities Commission (Maine Commission) selects the Project through a request for proposals (RFP) for both renewable energy projects in northern Maine and a 345 kV transmission line to connect the projects to the ISO New England Inc. (ISO-NE) transmission system in southern Maine (Northern Maine RFP).  FERC denied the request for negotiated rate authority because MPL did not shown that it has assumed the full market risk for the Project.  In evaluating negotiated rate applications, FERC employs a four-step analysis, as outlined in Chinook, to examine:  (1) the justness and reasonableness of the rates; (2) the potential for undue discrimination; (3) the potential for undue preference, including affiliate preference; and (4) regional reliability and operational efficiency requirements.  This approach, which was further developed in the 2013 Policy Statement, simultaneously acknowledges the financing realities faced by merchant transmission developers, the mandates of the FPA, and the Commission’s open access requirements.  Moreover, this approach allows the Commission to use a consistent framework to evaluate requests for negotiated rate authority from a wide range of merchant transmission projects that can differ from one project to the next.
 
To approve negotiated rates for a transmission project, the Commission must find that the rates are just and reasonable.[1]  In determining whether negotiated rates will be just and reasonable, the Commission considers whether the merchant transmission developer has assumed the full market risk for the cost of constructing its proposed project and is not building within the footprint of the developer’s (or an affiliate’s) traditionally regulated system.  In such a case, there are no captive customers that would be required to pay the costs of the project.  The Commission also considers whether the developer or an affiliate already owns transmission facilities in the region where the project is to be located, what alternatives customers have, whether the developer can erect any barriers to entry among competitors, and whether the developer would have any incentive to withhold capacity.
 
FERC denied MPL’s application because MPL had not met its burden under the first Chinook factor to show that the negotiated rates will be just and reasonable.  As noted above, in determining whether negotiated rates will be just and reasonable, the Commission considers whether the applicant has assumed the full market risk for the cost of constructing its proposed project.  As part of that analysis, the Commission evaluates whether there are any “captive” customers who would be required to pay the costs of the project.[2]  In short, to receive authorization to charge negotiated rates, an applicant must show that it has assumed the full market risk of its project; it must do so by sufficiently demonstrating that it has no ability to shift risk or pass any costs onto parties or neighboring utilities that are not participating in the project.[3]  We find that MPL has failed to make such demonstration here.  Based on the record before us, we find that the Northern Maine Renewables Act is ambiguous as to the obligations of the transmission and distribution utilities that would be taking service over the selected transmission project.  Under the Northern Maine Renewables Act, “the [Maine Commission] shall approve a contract or contracts between one or more transmission and distribution utilities and the bidder of any proposal selected by the commission,” and the Maine Commission “shall . . . [a]t its discretion . . . use or direct one or more transmission and distribution utilities as contracting parties under this section to participate in a regional or multistate competitive market or solicitation.”[4]  While it is clear that the transmission and distribution utilities may be compelled to participate in the solicitation process, it is not clear whether such participation obligates them to execute the TSA and to take service under the TSA over the selected transmission project.  If so required, the transmission and distribution utilities may be required to assume some of the Project’s market risk under negotiations that are not at arm’s length, i.e., the Maine Commission would direct them to purchase transmission service from MPL.  Therefore, based on the record and the ambiguity in the Northern Maine Renewables Act discussed above, FERC was unable to conclude that MPL would not have captive customers.  In addition, MPL also did not provide any information identifying the alternatives that customers could utilize or that would provide any competitive or cost-based alternatives that would place a check on its rates.  Accordingly, MPL did not provide sufficient evidence to meet the first Chinook factor.  
 
The four-factor analysis under Chinook requires that an applicant for negotiated rate authority meet each of the four factors.  Because MPL has not shown that negotiated rates will be just and reasonable under the first prong of the Chinook analysis, FERC did not decide whether MPL’s application meets the second, third, or fourth factors of the analysis.  FERC’s action does not prejudge any terms, rates, and conditions of any TSAs associated with the Northern Maine RFP that are filed with the Commission.

[1] Chinook, 126 FERC ¶ 61,134 at P 37.

[2] See Chinook, 126 FERC ¶ 61,134 at P 38; see also, id. P 1 n.1 (“Merchant transmission projects are distinguished from traditional public utilities in that the developers of merchant projects assume all of the market risk of a project and have no captive pool of customers from which to recoup the cost of the project.”).

[3] Lake Erie Connector, 144 FERC ¶ 61,203, at P 13 (2013) (“No entity on either end of the Project is required to purchase transmission service from [Lake Erie], and customers will do so only if it is cost-effective.”); Hudson Transmission, 135 FERC ¶ 61,104 at P 20 (“No entity operating on either end of the Project is required to purchase transmission service from Hudson Transmission, and customers will do so only if it is cost-effective.”); Tres Amigas LLC, 130 FERC ¶ 61,207, at P 52 (2010) (“While the design of the Project is somewhat different from merchant transmission projects previously considered by the Commission (e.g., it is designed in a way that requires interconnecting utilities to build transmission lines to it), such a design does not shift a portion of the risk of the Project onto these utilities.  Neighboring utilities are under no obligation to connect to or purchase service from Applicant, and they will only do so if it provides sufficient value to justify the new construction.  Accordingly, we find that the Project does not shift the market risk to any other entity.”).

[4] Me. Stat. tit. 35-A § 3210-I(2)(E), -I(4)(C).

On February 17, 2022 in Docket No. ER20-1068, FERC issued an order on rehearing on the RTO Adder for Dayton Power and Light Company (“Dayton”).   FERC initially found and continued in the rehearing order to find that Dayton does not qualify for a 50-basis point RTO Adder under FERC’s current incentives policy because:  (1) Order No. 679, as interpreted in CPUC, requires a showing of voluntary membership in such a Transmission Organization,  and (2) Dayton’s membership in a Transmission Organization is not voluntary because the Ohio statute requires it. 

FERC was not persuaded that it erred in concluding that parties must demonstrate voluntariness to qualify for the RTO Adder.  As discussed in the RTO Adder Order,[1] Order No. 679, as interpreted by CPUC, requires a showing of voluntariness.  Section 219(c) states that, “[i]n the rule issued under this section, the Commission shall, to the extent within its jurisdiction, provide for incentives to each transmitting utility or electric utility that joins a Transmission Organization.”  The Commission implemented this directive in Order No. 679, finding that an RTO Adder is appropriate for entities that choose to remain members of a Transmission Organization because, in relevant part, continuing membership is “generally voluntary.”[2]  As the court in CPUC observed, the Commission:
has a longstanding policy that rate incentives must be prospective and that there must be a connection between the incentive and the conduct meant to be induced.  This policy is incorporated in Order 679.  The policy prohibits FERC from rewarding utilities for past conduct or for conduct which they are otherwise obligated to undertake.[3] 

FERC reasserted in the Rehearing Order that it continues to believe that “only providing incentives to induce future voluntary conduct” is good policy and appropriately balances Congress’s direction in FPA section 219(c) with section 219(d)’s requirement that rates, including incentive adders, must remain just and reasonable and not unduly discriminatory or preferential.  In addition, that policy has been incorporated into Commission precedent on incentives through notice-and-comment rulemaking, and FERC believes it would be inappropriate to unilaterally abandon that policy in an adjudication involving a single public utility, especially when the Commission has opened a rulemaking proceeding to consider this very issue, among others (this rulemaking is pending at the Commission).

Commissioner Danly dissented.  He stated that he would grant rehearing and approve Dayton’s 50 basis point adder for Regional Transmission Organization (RTO) participation.  He repeated that section 219(c) of the FPA states that “the Commission shall . . . provide for incentives to each transmitting utility or electric utility that joins a Transmission Organization.”  There is no requirement in the statute for the utility to voluntarily join an RTO.  The Commission itself established that extra-statutory requirement in Order No. 679 and subsequent orders.  He stated that he is not aware of an instance where an appellate court has ruled that the Commission’s Order No. 679 interpretation is consistent with the statute, for he concludes that it is not.  Nothing in the majority’s opinion on rehearing changed his mind about the plain language of section 219(c).  He concludes that the “voluntariness” requirement is the Commission’s creation and remains at odds with the statute.
​
In February 2022, in Docket No. ER22-34, the Office of the Ohio Consumer Counsel filed a complaint against AEP, ATSI and Duke Energy Ohio, asserting that each companies’ Ohio transmission rates are excessive as they contain the RTO Adder which the Commission had just determined Dayton was not eligible because its membership in a transmission organization is mandatory under Ohio law.  This complaint remains pending before the Commission.

In April, Dayton, AEP, ATSI and Duke Energy Ohio appealed FERC’s orders to the DC Court of Appeal. 


[1] RTO Adder Order, 176 FERC ¶ 61,025 at PP 26-30.

[2] Order No. 679, 116 FERC ¶ 61,057 at P 331.

[3] CPUC, 879 F.3d at 977.

In Docket Nos. EL21-66 and ER21-1647,  FERC issued an order on rehearing dated March 24, 2022 which denied the NY Transmission Owners’ (NYTO) request to self-fund system Upgrades associated with interconnections and charge interconnection customers a revenue requirement over time that includes a return component.  The NYTOs asserted in these cases that the existing funding mechanism is unjust and unreasonable because it does not allow transmission owners to recover a reasonable rate of return to compensate them for the risks and costs associated with owning, operating, and maintaining the System Upgrades.  The NYTOs asked FERC to direct NYISO to amend the OATT and Market Administration and Control Area Services Tariff (collectively, Tariffs) to allow the NYTOs to provide initial funding for System Upgrades caused by generator interconnections and charge the interconnection customer to recover a return on and of this cost.  In an earlier order, FERC found that the NYTOs did not meet their initial burden under section 206 of the FPA to demonstrate that the existing funding mechanism is unjust, unreasonable, unduly discriminatory, or preferential and therefore did not reach the question of whether the NYTOs’ proposed replacement rate, TO Initial Funding, is just, reasonable, and not unduly discriminatory or preferential.  FERC explained that:  (1) the precedent cited by the NYTOs – Bluefield Water Works & Improvement Co. v. Public Service Commission, FPC v. Hope Natural Gas Co., and Ameren Services Co. v. FERC – does not require a change to NYISO’s existing funding mechanism for System Upgrades; and (2) the NYTOs had not presented sufficient evidence to show that the existing funding mechanism results in the NYTOs facing uncompensated risks and costs associated with the System Upgrades that force the NYTOs to operate segments of their business on a non-profit basis or prevent the NYTOs from attracting needed capital.  FERC affirmed this finding in its rehearing order.    

On March 17, 2022, FERC issued an Order in Docker ER16-2320 granting Pacific Gas and Electric (PGE) a return on equity (ROE) of 9.26% for the period March 2017 to February 2018 on its transmission investment.  On October 15, 2020, FERC issued an order addressing most exceptions to the October 1, 2018 Initial Decision regarding whether the rates proposed by PGE in its eighteenth revised transmission owner tariff (TO18) filing were just and reasonable and not unduly discriminatory or preferential.  The Commission also established a paper hearing on the limited issue of whether and how to apply the revised ROE methodology adopted by FERC in Opinion No. 569 et seq., to determine PG&E’s ROE.  With briefing having concluded, we here address outstanding matters regarding PG&E’s ROE. 
 
In its TO18 filing, PGE requested a base ROE of 10.4%, but no lower than 10.25%.  To support this proposal, PGE’s witness assessed PGE’s cost of equity by (1) estimating the cost of equity values for other electric utilities with comparable risks to PGE, and (2) considering the effects of current capital market conditions.  Acknowledging the process outlined by FERC in Opinion No. 531 (a ROE decision that proceeded Opinion 569), PGE applied a two-step discounted cash flow (DCF) model to determine a zone of reasonableness and then utilized other models to support the placement of a specific ROE value within that zone.  According to PGE, the results of the alternative models, as well as a survey of state-approved ROEs, indicate that the median values derived from the DCF methodology are too low to be considered reasonable.  Therefore, PGE proposed an ROE from the upper end of its calculated range.  PGE also requested a 50-basis point adder to recognize its participation in California Independent System Operator Corp. (CAISO) and thus a total ROE of 10.9%.
 
FERC applied the revised base ROE methodology adopted in Opinion No. 569, as modified in Opinion Nos. 569-A and 569-B, to PGE for this 2017/2018 period.  In Opinion No. 569-A, FERC noted that, in future proceedings, “parties will have an opportunity to argue that the base ROE methodology . . . should be modified or applied differently because of the specific facts and circumstances of the proceeding involving that party.”  No party has demonstrated that FERC’s base ROE methodology should be modified or applied differently to the facts and circumstances of this proceeding.  Applying FERC’s base ROE methodology to the facts of this proceeding, FERC found that 9.26% is the just and reasonable base ROE for PG&E for the TO18 rate period, i.e., from March 1, 2017 through February 28, 2018.