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.
Dr. Paul Dumais
CEO of Dumais Consulting with expertise in FERC regulatory matters, including transmission formula rates, reactive power and more.