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. 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. 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. 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.” 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.
 Chinook, 126 FERC ¶ 61,134 at P 37.
 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.”).
 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.”).
 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, 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.” 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.
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.
 RTO Adder Order, 176 FERC ¶ 61,025 at PP 26-30.
 Order No. 679, 116 FERC ¶ 61,057 at P 331.
 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.
Public Service of New Mexico Sets Reactive Power Rate to Zero to Avoid Paying Reactive Power Compensation to Unaffiliated Resources
On September 30, 2021, Public Service of New Mexico (PNM) filed at FERC in Docket No ER21-2988 to add a pass-through mechanism to its Schedule 2 (reactive power) for recovery from customers of reactive power compensation paid to unaffiliated resources with a FERC approved rate. They also filed to set their Schedule 2 rate to zero, by which they would cease paying their own or affiliated generators for reactive power and thereby not have to pay for reactive power from unaffiliated resources. PNM, however, provided for continued payment to New Mexico Wind, which had an effective Schedule 2 rate when PNM made this filing. FERC denied the pass-through mechanism (PNM did not adequately show it was just and reasonable) and accepted the zero rate for Schedule 2. FERC found that PNM’s proposed revisions to eliminate compensation for reactive service under Schedule 2 are just and reasonable. Consistent with Commission precedent, a transmission provider may decide to eliminate compensation for having the capability of providing reactive service within the standard power factor range. As the Commission has stated, “[t]he decision to compensate affiliates and non-affiliates [for reactive service capability] rests with the transmission provider.” FERC found that PNM’s proposed Schedule 2 revisions to eliminate compensation for its own generation and the associated charges to transmission customers is permitted under, and consistent with, Commission policy.
However, regarding PNM’s proposed pass-through proposal, FERC found that, upon Commission acceptance of PNM’s revisions to eliminate compensation for reactive power provided by its own generation, it would be unduly discriminatory or preferential for PNM to continue compensating an existing wind facility for reactive service capability within the standard power factor range while compensating no other generators for reactive service capability within the standard power factor range. Commission policy requires that the transmission provider compensate affiliated and unaffiliated generators on a comparable basis, and the Commission has stated that “an unaffiliated generator should not receive compensation for reactive power inside the [standard power factor range] unless the transmission provider so compensates its own or affiliated generators.”
With respect to the effect of FERC’s decision on New Mexico Wind’s and Aragonne Wind’s rate schedules for reactive service compensation, FERC noted that as of the October 1, 2021 effective date of PNM’s revisions to eliminate Schedule 2 compensation, third-party generators, including New Mexico Wind and Aragonne Wind, will not be entitled to receive compensation for Schedule 2 service. Section 9.6.3 of the New Mexico Wind and Aragonne Wind LGIAs reflects the Commission’s comparability policy for reactive service compensation and precludes New Mexico Wind and Aragonne Wind from Schedule 2 compensation as of October 1, 2021. However, FERC clarified that New Mexico Wind is entitled to receive compensation for its reactive power revenue requirement at its filed rate, subject to the outcome of the hearing and settlement procedures in Docket No. ER21-1555-000, from the effective date of its filed rate schedule until September 30, 2021 (Aragonne Wind did not yet have an effective Schedule 2 rate on October 1, 2021). After September 30, 2021, neither PNM nor third-party generators will receive compensation for Schedule 2 reactive service. FERC stated in conclusion that resources like New Mexico Wind and Aragonne Wind, by designing their generating facilities to have the capability to provide reactive support, are only meeting the conditions of interconnection required of all generators and they not entitled to compensation unless the transmission provider pays its own or affiliated generators for reactive power within the established range.
 Bonneville Power Admin. v. Puget Sound Energy, Inc., 120 FERC ¶ 61,211, at P 20 (2007) (“Commission policy clearly allows [Bonneville Power Administration] to discontinue paying all its merchants for inside the [standard power factor range] reactive power service.”), order on reh’g, 125 FERC ¶ 61,273 (2008) (Bonneville Rehearing Order); E.ON U.S. LLC, 119 FERC ¶ 61,340, at P 15 (2007) (E.ON) (accepting proposal to compensate no generators for reactive power within the standard power factor range); Entergy, 113 FERC ¶ 61,040 at P 38 (accepting tariff revisions setting charge for reactive power to zero).
 Bonneville Rehearing Order, 125 FERC ¶ 61,273 at P 25 (noting further that the transmission provider “is under no obligation” to choose to compensate for reactive power within the standard power factor range).
 See Order No. 2003-B, 109 FERC ¶ 61,287 at P 119.
 Bonneville Rehearing Order, 125 FERC ¶ 61,273 at P 24.
On January 28, 2022, FERC issued Opinion 577 involving Pacific Gas and Electric (PG&E) and the City of San Francisco (City). The City requested additional service at a King Street Substation, the interconnection point with PG&E. PG&E performed a system impact study and determined the facility additions needed to provide the service the City requested. PG&E treated the facilities as direct assignment facilities and the City objected, saying they were upgrades.
The Initial Decision addressed four disputed issues: (1) whether the facilities at issue are properly categorized as direct assignment facilities under the WDT (Issue One); (2) if the facilities are not direct assignment facilities, then whether the facilities are “upgrades” under the WDT Interconnection Agreement (Issue Two); (3) whether PG&E is permitted, under the WDT and Commission policy, to directly assign San Francisco the full cost of facilities at issue where PG&E also requires San Francisco to pay the WDT distribution service charge (Issue Three); and (4) whether PG&E should be required to provide more detailed support for cost estimates in the WDT application process (Issue Four).
On Issue One, FERC found that the facilities were properly classified as direct assignment facilities, as they are for the sole use and benefit of the City. FERC also found that that since the facilities are properly classified as direct assignment facilities, it was not necessary to address the issues concerning whether the facilities are “upgrades” under the WDT Interconnection Agreement. Regarding Issue Three, FERC found that PG&E is permitted by Commission policy and the WDT to directly assign the costs of the King Street Substation facilities to San Francisco and require San Francisco to pay the WDT distribution service charge. As to Issue Four, FERC found that PG&E needs to provide a more detailed cost estimate to the City in connection with the King Street Project.
Further Information on Two Items
As to charging the City for the direct assignment facilities and for its charge under the tariff, FERC found this to be consistent with its Transmission Pricing Policy. FERC found that because direct assignment facility costs are netted out and excluded from PG&E’s revenue requirement that is used to calculate the distribution service charge, direct assignment facility costs are not included in the distribution service charge and the City is not paying twice for the same service. That is, because there is no cost overlap between the direct assignment facilities that the City pays for and the costs included in the distribution service charge, PG&E is not violating the “and” pricing policy.
FERC disagreed with the Presiding Judge’s finding that it is unjust and unreasonable “that the design of a distribution system to provide a customer electric service is within the sole discretion of the Distribution Provider.” Rather, distribution providers maintain discretion over their own systems. Each distribution utility, including the City, retains sole discretion over the provision of electric service to its own retail customers, and when two distribution utilities with a utility-to-utility relationship like here interconnect their systems at a point of interconnection, such as the City ’s WDT points of delivery, each distribution provider retains sole discretion over the management of the distribution system on its own side of the interconnection. Just as the City retains sole discretion over the provision of power to the SFMTA as its retail customer on its side of the interconnection at the King Street Project, PG&E retains discretion over the distribution facilities on its side of the interconnection.
In Docket No. ER21-2282, the PJM TOs requested that they have the option to fund Network Upgrades (transmission facilities necessary to interconnect new generation to the PJM system). The PJM TOs state that this option is necessary to ensure that the PJM TOs are properly compensated for owning and operating Network Upgrades, and this optionality is modeled after the provisions in the MISO Tariff that the Commission recently found to be just and reasonable. The PJM TOs explained that there is a sharp increase in the number of renewable generation resources interconnecting to the PJM transmission system in recent years and the growing amount of Network Upgrades necessary to accommodate those interconnection requests was the driver of the PJM TOs decision to file the Proposed Revisions to its tariff. The trend in generator interconnections is expected to continue, if not accelerate, in the coming years, and there are approximately $4.9 billion of Network Upgrades associated with generation projects that have been studied by PJM and are currently in the interconnection queue. In addition, there are more than 1,200 generation projects waiting to be studied by PJM.
The PJM TOs state in their brief filed on January 13 they are not currently compensated for the risk of owning and operating Network Upgrades, though they are compelled to own and operate Network Upgrades (the generator reimburses the TO for the cost), which produces risk without the attendant compensation. Moreover, because they receive no profit for Network Upgrades, as the amount of Network Upgrades on their system increases, the overall return for their other transmission facilities in rate base is effectively reduced. The PJM TOs state that in Ameren, the Court of Appeals for the District of Columbia expressed concern that the MISO transmission owners were required to own and operate Network Upgrades with no profit or compensation. On remand, the Commission agreed, finding that Network Upgrades present risks and the MISO Transmission Owners should be compensated for those risks. The same reasoning should apply in PJM.
The PJM TOs also state that Network Upgrades are transmission facilities and the PJM TOs face the same risks in owning and operating Network Upgrades as they do in owning and operating other transmission facilities. Accordingly, it is just and reasonable for the PJM Transmission Owners to be compensated for owning and operating Network Upgrades in the same manner that they are compensated for owning and operating other transmission facilities, including the use of the same base Return on Equity (“ROE”).
The PJM TOs state the FERC’s rationale adopted in the recent order denying funding of Network Upgrades of the NY TOs, that a utility’s risk profile of the enterprise as a whole accounts for the risks of Network Upgrades is flawed both legally as well as from an implementation perspective as the Commission’s ROE methodology is simply not designed to or capable of the precision necessary to account for the risks of individual transmission facilities in developing a risk profile used to establish a transmission owner’s ROE.
Lastly, the PJM TOs state that FERC should have no concerns regarding undue discrimination as
there are ample measures to protect against affiliate abuse concerns. Importantly, PJM
will maintain its key role in the interconnection process. In addition, the information that
the PJM TOs propose to post on the PJM website (combined with the detailed information that already exists on the PJM website) will provide significant, detailed information to allow interested parties to evaluate whether disparate treatment or undue discrimination has occurred, and to support a complaint pursuant to Section 206 of the FPA, if warranted. And the entirety of the Commission’s regulatory framework, including numerous rulemaking orders adopted over the past three decades, are in place to prevent affiliate abuse and undue discrimination.
For the PJM TO filing, go to https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20220113-5168&optimized=false.
On December 21, 2021, in Docket No. ER21-2882, FERC denied Pacific Gas and Electric’s (“PG&E”) request to recover 50% of the abandoned plant costs associated with three projects which CAISO had not canceled but had changed the scope. PG&E had requested authorization to recover 50% of abandoned plant costs associated with three transmission projects that the CAISO approved and then subsequently modified: (1) the Spring/Morgan Hill Area Reinforcement Project (Spring/Morgan Hill Project), (2) Oro Loma 70 kV Reinforcement Project (Oro Loma Project), and (3) Lockeford–Lodi 230 kV Area Development Project (Lockeford–Lodi Project) (collectively, Projects). PG&E explains that it identified the project costs it seeks to recover by forming a Project Cost Review Team (Review Team) that was responsible for assessing the costs of the Projects. The Review Team evaluated PG&E’s work for the Projects as originally designed and compared them with the scope of each revised Project to identify those costs that would no longer be useful for the rescoped Projects. PG&E sought recovery of 50% of the approximately $11.8 million ($5.89 million) the Review Team determined were no longer useful to the rescoped Projects, with PG&E writing off the remaining $5.89 million.
PG&E did not assert that CAISO had recommended abandonment of any of the Projects, but rather that the “rescoping” of the Projects through CAISO’s regional transmission planning process had resulted in a reduction in size and cost of the Projects to such an extent that the originally conceived Projects have been “essentially cancelled” and, therefore, should be eligible for abandoned plant cost recovery treatment under Opinion No. 295. However, PG&E cited no authority to support its theory that the Commission should permit such cost recovery where projects have been “rescoped,” and FERC saw no reason here to deviate from the Commission’s well-established policy. The Projects are designated as active and ongoing within CAISO’s 2020-2021 Transmission Plan, and CAISO has assigned 2025 and 2026 expected in-service dates for them. Therefore, FERC found that the Projects have not been abandoned and do not qualify for abandoned plant cost recovery treatment pursuant to Opinion No. 295. Further, unlike in situations where projects have been abandoned, the Commission’s accounting procedures provide for the capitalization of construction costs once the Projects go into service; therefore, PG&E will have the opportunity to seek recovery of the relevant costs at that time.
On December 16, 2021, in Docket RM20-16, FERC issued a final rule on Managing Transmission Line Ratings (Order 881). Through this rule, FERC is requiring:
FERC defines a transmission line rating as the maximum transfer capability, computed in accordance with a written methodology and good utility practices, considering the technical limitations on conductors and other equipment (thermal flow limits), as well as technical limitations of the transmission system (voltage and stability limitations). The transfer capability of a transmission line can change with ambient weather conditions. Increases in temperature lower the transfer capability while decreases in temperature increase transfer capability. The continued use of seasonal or static transmission line ratings based upon conservative, worst-case assumptions, results in suboptimization of the transmission line.
FERC requires the following:
Though not ordered in this proceeding, FERC initiated a subsequent proceeding, Docket No. AD22-5, to consider dynamic line ratings (“DLR”), which presents opportunities for transmission line ratings that are more accurate than those established with AARs. Unlike AARs, DLRs are based not only on forecasted ambient air temperatures and the presence or absence of solar heating, but also on other weather conditions such as (but not limited to) wind, cloud cover, solar heating intensity (instead of mere daytime/nighttime distinctions used in AARs), and precipitation, and/or on transmission line conditions such as tension or sag. FERC adopted the definition of DLR as a transmission line rating that: (1) applies to a period of not greater than one hour; and (2) reflects up-to-date forecasts of inputs such as (but not limited to) ambient air temperature, wind, solar heating intensity, transmission line tension, or transmission line sag.
In this rule, FERC also requires transmission providers to use uniquely determined emergency ratings for contingency analysis in the operations horizon and in post-contingency simulations of constraints. Such uniquely determined emergency ratings must also incorporate an adjustment for ambient air temperature and daytime/nighttime solar heating, consistent with our AAR requirements for normal ratings. Most transmission equipment can withstand high currents for short periods of time without sustaining damage. Emergency ratings reflect this technical capability, defining the specific additional current that a transmission line can withstand and for what duration the transmission line can withstand that additional current without sustaining damage. Because emergency ratings reflect this capability, uniquely determined emergency ratings will ensure more accurate transmission line ratings.
FERC requires each transmission provider to submit a compliance filing within 120 days of the effective date of this final rule, revising their OATT to incorporate pro forma OATT Attachment M. FERC further require that all requirements adopted in the rule be fully implemented no later than three years from the compliance filing due date.
Dr. Paul Dumais
CEO of Dumais Consulting with expertise in FERC regulatory matters, including transmission formula rates, reactive power and more.