FERC Workshop on Capacity Allocation for New Merchant Transmission Projects and New Cost-Based, Participant-Funded Transmission Projects

On February 28, 2012, the Federal Energy Regulatory Commission (FERC or “Commission”) held a workshop focusing on capacity allocation policies for new merchant transmission projects and cost-based, participant-funded transmission lines.

Workshop Procedure

At the conference, participants were split among four groups: (i) generators and customers; (ii) merchant transmission developers; (iii) traditional utilities; and (iv) state regulatory groups/Regional Transmission Organizations (RTOs). Each of these groups was given 30 minutes to discuss several questions posed by the Commission, and at the end of discussion, the groups reconvened to report the general consensus opinion of each group. Then, the workshop was opened to additional questions and comments.

Capacity Allocation for New Merchant Transmission Projects

Prior to the Commission’s Chinook order in 2009,1all merchant transmission capacity was required to be allocated during an open season.  However, after Chinook, the Commission allowed, on a case-by-case basis, some shares of capacity to be presubscribed via an “anchor customer,” with the remaining capacity allocated in an open season. In its 2010 Sunzia order,2the Commission denied a specific request to allocate 100 percent of capacity to anchor customers, but did not preclude the possibility of 100 percent anchor customer allocation altogether. At its February 28 workshop, the Commission requested participants’ comments on whether the Commission should return to a pre-Chinook, 100 percent open season allocation requirement, but which also “allow[s] for distinctions among prospective customers in the open season based on transparent and not unduly discriminatory criteria, with the possible result that a single customer could be awarded up to 100 percent of capacity.”3

The merchant transmission developers group expressed the most concerns over requiring 100 percent open season allocation. A consensus of the merchant transmission developers argued that such a requirement places developers at increased risk and uncertainty, because there is no guarantee that developers will receive sufficient and desirable subscriptions. The Commission has previously characterized this problem as the “‘chicken-and-egg’ scenario that arises when generators, purchasers and transmission owners all wait for the other to commit money to a project before committing themselves.”4The merchant transmission developers argued at this workshop, as they have previously, that “the financial commitments made by anchor customers prior to an open season provide crucial early support and certainty to merchant transmission developers, which enables them to gain the critical mass necessary to develop these projects.”5The developers stressed that these new merchant transmission projects are extremely difficult to build. Certain developers claimed that, if there is not a 100 percent commitment of capacity, from a financial viewpoint, such projects should not be built. One developer went so far as to say that from a developers’ perspective, a 100 percent open season requirement is simply a nonstarter. The traditional utilities group stated that its primary concern with an open season requirement was that the current process for open seasons takes too long.  In contrast, the generators group claimed that the current capacity allocation process is adequate.

Characteristics of a Well-Designed Open Season Process  – The Commission asked the groups to discuss what would be the characteristics of a well-designed open season process. The merchant developers continually emphasized that the capacity allocation policy that the Commission adopts should allow for bilateral negotiations. Numerous open questions between a developer and a generator or customer need to be resolved in such negotiations, including among others: (i) the project schedule; (ii) who bears the risk if the project does not come on line; (iii) who bears the risk if the line has an outage; (iv) when is the project declared in service; (v) when does the customer begin paying; and (vi) termination rights. The state regulatory/RTO group added that there were lessons that could be learned from the natural gas industry which in certain instances has been permitted to use an anchor customer model. 

Right Sizing – The Commission asked the groups to discuss the criteria that should be used in “right sizing,” or evaluating whether a developer has appropriately sized a transmission line. The traditional utilities stated that due to the risks and costs involved in putting together new merchant transmission projects, appropriate size is often determined by building to “economic size...and no more.” The RTOs argued that there is no agreement on what criteria determines right size.

Discrimination – The parties discussed the issue of how to prevent undue discrimination in a presubscription process. The developers group stated that there is an inherent tension between selecting customers who will be successful and not discriminating. The representative from SunZia said that to a certain extent, in order to select the right customer, a developer needs to be able to discriminate. For example, a developer should be able to discriminate on the basis of certain factors such as credit rating and the length of the contract term offered by the customer/generator. The developers appeared to be concerned about the fact that generators not chosen for a project could file a Federal Power Act section 206 complaint as a “backstop,” which may prevent that project from coming on line and further emphasized the difficulty of getting these new merchant transmission projects built.

Capacity Allocation for New Cost-Based, Participant-Funded Transmission Projects

The Commission asked the participants to discuss capacity allocation for new cost-based, participant-funded transmission projects. Because the Commission anticipates more “innovative proposals from transmission developers seeking to construct facilities for the use of specific customers in exchange for recovering the cost of the facilities from those customers...questions of customer access to capacity for such cost-based projects will arise.”6Currently, the Commission does not require nonincumbent developers of new cost-based, participant-funded transmission projects to use an open season. Nor is an incumbent transmission provider required to follow service request procedures set forth in the pro forma Open Access Transmission Tariff (OATT). In its notice, the Commission asked, among other questions: (i) whether an incumbent/nonincumbent distinction is relevant for the purposes of capacity allocation; (ii) whether nonincumbent transmission developers should allocate capacity on cost-based, participant-funded projects through an open season; and (iii) whether incumbent public utility transmission providers should use service request and transmission planning rules contained in their OATTs for the development of all new transmission facilities.

For most of the questions posed by the Commission on cost-based, participant-funded projects, including whether incumbent developers should be required to follow service request procedures set forth in their OATTs, the groups were unable to reach a consensus, and simply deferred, stating that “there is more to be done in this area.”

However, all groups seemed to agree that a distinction between incumbent public utility transmission providers and nonincumbent transmission developers is appropriate and significant, as incumbent developers already have a set of rules to govern the processing of service requests and planning of grid expansion, whereas nonincumbent developers do not.

Furthermore, the developers and the generators groups seemed to agree that when a nonincumbent is developing a new cost-based, participant-funded transmission project, an open season may undermine a project’s ability to succeed for the same reasons it would undermine new merchant transmission projects. That is, an open season does not provide the same ability to secure early support and certainty that an anchor customer would.


1Chinook Power Transmission, LLC, 126 FERC ¶ 61,134 (2009).

2SunZia Transmission, LLC, 131 FERC ¶ 61,162 (2010).

3Allocation of Capacity on New Merch. Transmission Projects & New Cost-Based, Participant-Funded Transmission Projects, Notice of Workshop, issued Jan. 31, 2012, Docket Nos. AD12-9-000, et al. (“Notice”).

4Chinook Power Transmission, LLC, 126 FERC ¶ 61,134 at P 44 (2009).

5Id.

6Notice at 4.

Contact Information

If you have any questions regarding this alert, please contact—

G. Philip Nowak
pnowak@akingump.com
202.887.4533
Washington, D.C.
Julia E. Sullivan
jsullivan@akingump.com
202.887.4537
Washington, D.C.
Scott D. Johnson
sdjohnson@akingump.com
202.887.4218
Washington, D.C.