Keywords: FERC, policy statement, capacity allocation, new transmission projects

On January 17, 2013, the US Federal Energy Regulatory Commission (FERC) issued a final Policy Statement1 (Statement) to refine and clarify its policy guidance regarding capacity allocation for new merchant transmission projects and non-incumbent cost-based, participant-funded transmission projects. The revised policy became effective on January 17, 2013, and follows from a related technical conference in March 2011, a workshop in February 2012 and a proposed policy statement issued on July 19, 2012.2 By assuring the availability of transmission-to-phased projects and providing greater rate certainty for the owners and financing parties of such facilities, the Policy Statement should facilitate the development of new generation projects, such as wind farms, that require the construction of associated transmission facilities.

In the decade since FERC first authorized negotiated-rate authority for a merchant transmission project developer, the agency has sought to incentivize transmission development while ensuring that transmission access is non-discriminatory and that rates are just and reasonable. In its prior policy, FERC had identified 10 criteria3 to guide its determination that negotiated-rate authority would be just and reasonable for a particular merchant transmission, two of which were (i) an open season process to initially allocate related transmission capacity and (ii) posting the results of the open season process on an open-access same-time information system and filing the results in a report with FERC. In several recent orders, an evolving FERC policy adopted different rules regarding capacity allocation for merchant transmission projects and for non-incumbent cost-based, participant-funded transmission projects.

In Chinook PowerTransmission,4 FERC adopted a four-factor analysis5 for evaluating merchant transmission projects. Under this analysis, FERC relies on the open season process and a post-open season report to provide required transparency in the allocation of related transmission capacity and ensure against undue discrimination (the second factor) and, if there is affiliate participation, to ensure no undue preference or other affiliate concerns (the third factor).

The Chinook order was also the first time that FERC authorized a developer to allocate capacity to an "anchor" customer as a means to permit developers to meet the financial challenges unique to merchant transmission development. Since Chinook, FERC has issued several orders authorizing allocations of up to 75 percent of a transmission project's capacity to anchor customers.

The Statement reflects FERC's current belief that it can provide more flexibility in the capacity allocation process, while still ensuring that the resulting allocation is not unduly discriminatory or preferential.6 The Statement makes several significant changes to prior policy, including the following:

  • Permitting up to 100 percent of the capacity on a new merchant or non-incumbent cost-based, participant-funded transmission project to be pre-subscribed or reserved (including by an affiliated customer);
  • Permitting an open solicitation of interest and resulting bilateral negotiations (in lieu of the previously required open season process);
  • Permitting a "first mover" customer to have more favorable rates, terms and conditions than later customers (instead of requiring that an anchor customer's terms be also offered to other customers in the related open season process);
  • Defining when capacity can be reserved for future projects, while preventing speculative withholding of transmission capacity; and
  • Requiring that the capacity allocation made under the policy to be reported to FERC and be a part of the required FERC approval proceeding (thus permitting challenges to be made to such allocation in such proceeding).

The Statement requires that the open solicitation include a "broad notice" of the proposed project that is issued in a manner to ensure that all potential and interested customers are informed. The notice must include the following items:

  • Project size/capacity: MW and/or kV rating (specific value or range of values);
  • End points of line (as specific as possible such as points of interconnection to existing lines and substations, although it may be potentially broad, such as Montana to Nevada, if the project is very early in development);
  • Projected construction and/or in-service dates;
  • Type of line—for example, AC, DC, bi-directional;
  • Precedent agreement (if developed); and
  • Other capacity allocation arrangements (including how it will address potential oversubscription of capacity and the criteria that the developer plans to use to select transmission customers—such as credit rating, "first mover" status and a customer's willingness to incorporate risk-sharing in the related transmission service agreements).

Subsequent notice is required of any changes in such information or the status of the capacity allocation process as the project's development continues. This process would replace the formal "open season" procedures previously required by FERC.

Once a final subset of potential customers has been identified by the developer through an open solicitation process, the developer may engage in bilateral negotiations with potential shippers for particular rates, terms and conditions, which FERC acknowledges may be individualized to meet project-specific needs. Differences in rates, terms and conditions will be permitted as long as they are based on transparent criteria that are not preferential or discriminatory; however, any deviation from FERC's pro forma open access transmission tariff (OATT) will still have to be justified when the developer files its OATT with FERC.

In particular, FERC will review the sizing of a transmission project to ensure that the developer's determination was based on objective criteria and was not the result of undue preference or discrimination.

The Statement requires that the final capacity allocation be disclosed, and it will require FERC's approval under section 205 of the Federal Power Act. FERC has a well-established declaratory order process that developers have used to seek approval of allocations, including reservations of available capacity for generation being developed by affiliates that meet criteria specified by FERC. FERC will allow a developer to seek advance approval of its process; alternatively, the developer may complete its process first and then seek FERC approval.

To obtain approval, the related developer must demonstrate that the process that led to the identification of the transmission customers and the related contracts was consistent with the Statement. The related developer also bears the burden of proof that the related process was not discriminatory or preferential and that it resulted in rates that are just and reasonable. FERC expects that such a demonstration will include, at a minimum, the:

  • Steps the developer took to provide broad notice, including the project information and customer evaluation criteria that were relayed in the broad notice;
  • Identity of the parties that expressed interest in the project, placed bids for project capacity and/or purchased capacity; and the capacity amounts, terms and prices involved in that interest, bid or purchase;
  • Basis for the developer's decision to prorate, or not to prorate, capacity, if a proposed project is oversubscribed;
  • Basis for the developer's decision not to increase capacity for a proposed project if it is oversubscribed (including the details of the economic, technical or financial infeasibility that is the basis for declining to increase capacity);
  • Justification for offering more favorable rates, terms and conditions to certain customers, such as "first movers" or those willing to take on greater project risk-sharing;
  • Criteria used for distinguishing customers and the method used for evaluating bids. This should include the details of how each potential transmission customer (including both those who were and those who were not allocated capacity) was evaluated and compared to other potential transmission customers, both at the early stage when the developer chooses with whom to enter into bilateral negotiations and subsequently when the developer chooses in the negotiation phase to whom to award transmission capacity; and
  • Explanation of decisions used to select and reject specific customers. In particular, the report should identify the facts, including any rates, terms or conditions of agreements unique to individual customers that led to their selection, and relevant information about others that led to their rejection. If a selected customer is an affiliate, FERC will look more carefully at the basis for reaching that determination to demonstrate sufficient transparency to FERC and other interested parties.

In the Statement, FERC reaffirms its prior policy that all developers of merchant and non-incumbent cost-based, participant-funded transmission projects will become public utilities at the time that the related project is energized (or possibly earlier) and that, under FERC's pro forma OATT requirements, a transmission service provider has an obligation to expand its transmission systems, if necessary, to provide transmission service. FERC notes that this obligation may mitigate to a degree concerns about undersized transmission projects, provided subsequent customers are willing to pay the costs of such expansions.

As a result of the Policy Statement and other recent FERC orders, developers of merchant transmission lines will have more flexibility in crafting commercial terms and greater certainty that bilateral negotiations will be acceptable. The emerging FERC policy also will enable generation developers, including those affiliated with the transmission developer, an enhanced ability to contract for transmission service to meet the needs of projects under development.

Originally published January 23, 2013

Footnotes

1 Available at http://ferc.gov/whats-new/comm-meet/2012/111512/E-3.pdf.

2 Available at http://www.ferc.gov/whats-new/comm-meet/2012/071912/E-4.pdf.

3 The 10 criteria were: (1) the merchant transmission facility must assume full market risk; (2) the service should be provided under the open access transmission tariff (OATT) of the Independent System Operator (ISO) or Regional Transmission Organization (RTO) that operates the merchant transmission facility and that operational control be given to that ISO or RTO; (3) the merchant transmission facility should create tradable firm secondary transmission rights; (4) an open season process should be employed to initially allocate transmission rights; (5) the results of the open season should be posted on the OASIS and filed in a report to the Commission; (6) affiliate concerns should be adequately addressed; (7) the merchant transmission facility not preclude access to essential facilities by competitors; (8) the merchant transmission facilities should be subject to market monitoring for market power abuse; (9) physical energy flows on merchant transmission facilities should be coordinated with, and subject to, reliability requirements of the relevant ISO or RTO; and (10) merchant transmission facilities should not impair pre-existing property rights to use the transmission grids of interconnected RTOs or utilities. For example, see Northeast Utilities I, 97 FERC ¶ 61,026 at 61,075.

4 126 FERC ¶ 61,134, at P 37 (2009) (Chinook). The Chinook order was reviewed in our March 4, 2009, Legal Update "New Rules for Electric Transmission Projects" available at http://www.mayerbrown.com/publications/New-Rules-for-Electric-Transmission-Projects-03-04-2009/.

5 The four factors are: (1) the justness and reasonableness of rates; (2) the potential for undue discrimination; (3) the potential for undue preference, including affiliate preference; and (4) regional reliability and operational efficiency requirements.

6 FERC takes care to note, however, that the policy guidelines, if followed, will only demonstrate that the developer has met the second and third Chinook factors and that, accordingly, the project must still demonstrate the remaining two factors; namely, that related rates are just and reasonable and that the project meets regional reliability and operational efficiency requirements.

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