FERC Filings
EPSA Comments on Changes In Status for Public Utilities with Market-Based Authority
COMMENTS
The October 6, 2004, NOPR outlines several proposed modifications to amend the Commission’s regulations, including the implementation of a 30-day reporting requirement from the time such changes occur to ensure that all material events are timely reported to the Commission (and which eliminates the option to delay reporting of such events until submission of a seller’s updated market power analysis for its triennial review), and the incorporation of the reporting requirement into the market-based rate tariff of each entity that is currently authorized to make market-based sales. The NOPR also sets forth numerous questions to be considered and commented on by interested parties, including inquiries on the language to be used to define those arrangements that would trigger the reporting requirement, whether and what threshold level of increases in generation would trigger the requirement, how such changes should be described and filed with the Commission, and whether the 30-day proposed time period for reporting is adequate.
EPSA agrees that all market participants must know with certainty what the “rules of the road” are and encourages the Commission to utilize this proceeding to provide specificity and clarity to the reporting requirement for changes in status. Clarity regarding this reporting requirement will result in accurate reporting and thus bolster the Commission’s oversight of wholesale electricity markets, thereby enabling those markets to remain workably competitive, which benefits all consumers in the long run. EPSA is concerned, however, that attempts to clarify this reporting requirement, as set out in the NOPR, may introduce additional confusion and uncertainty into wholesale electricity markets due to the structure of the NOPR, which poses several general inquiries and sets out few specific proposals. EPSA seeks clarity and finality on all issues related to market-based rate authority, and urges the Commission to proceed swiftly in the instant proceeding as well as the concurrent generic proceeding, Docket No. RM04-7.
A. Specifications of Triggering Events
EPSA urges the Commission to be clear in regard to its conclusions on “triggering events,” and to refrain from requiring “any and all” transactions that might be deemed trigger events for the proposed reporting requirement; rather it should rely on a materiality threshold for ownership or control as discussed below. A vague requirement undoubtedly will result in the reporting of transactions that need not be reported, such as those that will be reported in a related Section 203 filing, or worse, will require the reporting of transactions that do not impact an applicant’s potential to exercise market power, thus causing confusion and regulatory risk rather than providing clarity and certainty.
Pending further elaboration through a supplemental NOPR, EPSA believes that the current language for changes in circumstances, with one modification, will adequately capture transactions that may cause changes to an applicant’s market power within a particular geographic market. This language, as outlined in the NOPR, states,
With respect to the types of events that should trigger the reporting obligation, the Commission proposes that, as an initial matter, the following events would qualify as changes in status: (1) ownership or control of generation or transmission facilities or inputs to electric power production; or (2) affiliation with any entity not disclosed in the filing that owns or controls generation or transmission facilities or inputs to electric power production or affiliation with any entity that has a franchised service area.
Of note, fuel supply should remain exempted as an input to electric power production, and specifically, increased pipeline capacity holdings should not constitute a triggering input because firm capacity is obtained through FERC-authorized programs and is posted on the pipeline bulletin boards. In past orders regarding market-based rate authority, the Commission has considered these “inputs to electric power production” in its review of barriers to entry. In doing so, the Commission was willing to rely on the ability of market participants to file a complaint for denial or delays in service, or a requirement of unreasonable terms, conditions or rates for fuel-related services to a potential electric competitor. The Commission should continue to do so in this instance. In particular, the Commission should clarify that changes in ownership or control of the fuel commodity such as oil or gas will not trigger the notice requirement as such commodities are routinely and frequently traded by marketers.
EPSA further agrees with the Commission that it may be necessary to delineate language defining an entity’s control of assets within this reporting requirement rule. The NOPR explains, [T]he Commission’s guidelines for the assessment of mergers and its generation market power analysis for market-based rate authority provide that, for the purposes of the market power analysis, the capacity associated with contracts that confer operational control of a given facility to an entity other than the owner must be assigned to the entity exercising control over that facility, rather than to the entity that is the legal owner of the facility. In addition, with respect to notifications of changes in status, the Commission has found that an entity controls the facilities of another when it controls the decision-making authority over sales of electric energy, including discretion as to how, when and to whom it could sell power generated by these facilities.
While EPSA agrees that control over an asset is a key consideration in a market power analysis, EPSA believes the Commission’s use of the term “operational control” creates uncertainty. For example, consider a generator that has sold the scheduling and dispatch rights for its unit to an unaffiliated entity. In this instance, the purchasing entity has “control” of the unit as a result of its contractual right to schedule and dictate the terms of dispatch of the facility. However, if the generator’s employees are the physical operators of the plant, one could argue that the generator retains “operational control.” This, in EPSA’s view, would be a flawed interpretation of “operational control.” Therefore, the Commission should drop all references to “operational control” (and replace it with “scheduling and dispatch control”) or clarify that operational control refers to a contractual right to control the output of a plant.
1. Trigger Event Thresholds
In order to assess the materiality of an event or transaction, the NOPR sets out questions on the threshold level of increases in generation that would signal an event that could impact the continued basis of a grant of market-based rate authority and trigger the reporting requirement. The NOPR goes on to ask what amount of increase in generation might trigger the requirement. EPSA believes the Commission should establish some threshold level of generation capacity increase, perhaps measured by MW (in a range of 250 - 500 MW, for instance) or 1-2% of the installed capacity in a market area, under which reporting would not be required. Such an exemption is administratively efficient and poses virtually no risk of increased exercise of market power. The Commission must guard against instituting burdensome reporting requirements that require an ongoing recalculation of market power analysis by companies pursuant to every change in status report. Extensive analysis and market re-runs will simply not be necessary for every transaction. While the Commission is properly concerned with protecting customers against the exercise of market power, there must be a rule of reason to protect market participants against undue burdens. Such an exemption properly balances the need to protect customers with the burden placed on market participants.
While increase in market share in the relevant geographic market should be a key variable in defining triggering events, other actions by major entities – particularly those outside RTOs with affiliates that control transmission in the relevant market – must be considered as triggering events. Further, where affiliates have a role in the relevant market, any increase in control of generating capacity is likely to impact the competitive balance in that market. In tying the impact of the event to the marketplace, the Commission is correctly assessing the materiality of the event and its effect on competition, but it should err on the side of considering a wider range of transactions where a wholesale seller has affiliates operating in the relevant market outside of RTOs.
2. Section 203 Exemption
The Commission should clarify that transactions currently reviewed by the Commission under Section 203 of the Federal Power Act should be specifically excluded from the proposed reporting requirement. Any transaction or acquisition that is the subject of a 203 application will be adequately reviewed by the Commission, as the 203 analysis includes assessment of a transaction’s impact on competition. Such transactions include the transfer of jurisdictional transmission facilities or power contracts from one entity to another under the same corporate umbrella. As these transactions will be filed and investigated pursuant to Section 203, it would be duplicative and unnecessary to require a notice of change in status for the same event. Further, such a filing would not trigger a separate review, as such review has been or will be conducted by the Commission under Section 203.
B. Form and Content of Reports
As to the manner in which a non-exempt status change should be submitted to the Commission, EPSA agrees that the form and content of such reports should be as described by the Commission (transmittal letter with narrative explanation). Based on precedent, an applicant’s notice of a change in status should not change existing authorities or waivers until and unless the Commission issues a notice of the initiation of a Section 206 proceeding to investigate the transaction.
As to the form of reporting, a short transmittal letter explaining the transaction should suffice to put parties and the Commission on notice of any possible change in status. Requiring more of applicants would be administratively burdensome, costly and unnecessary. At its discretion, the applicant may include more extensive information and analysis in its initial report, or the Commission may request additional data. The Commission’s goal should be to adopt a cost-effective approach to protecting customers from the exercise of market power, while at the same time minimizing the costs and uncertainty associated with a change in status—and this approach would accomplish that goal.
C. NOPR Procedures and Progress
The NOPR sets forth numerous questions for consideration and comment in the process of proffering a proposal that even the Commission concedes “may be susceptible to different interpretations among market-based rate sellers concerning the scope of their reporting requirements.” EPSA agrees with the Commission that the current NOPR is in need of further clarity. For that reason, EPSA urges the Commission to first consider the comments filed in this proceeding, and then issue a supplemental NOPR to allow for comment on any and all specific language that represents the Commission’s then current thinking on the following: the transactions that would trigger the change in status filing, a materiality threshold for such transactions, and when in the life of the event the filing must occur.
EPSA’s request for a supplemental NOPR is not intended to delay the consideration of updating this reporting requirement. However, the request should be adopted for the following reasons. First, the Commission and other administrative agencies routinely issue a supplemental NOPR to, inter alia, clarify vague or ambiguous language in the original NOPR, address additional issues raised during the initial comment period, or to consider new and/or updated information that was not available at the time the original NOPR was issued, but is now relevant to the final rulemaking. Second, a supplemental NOPR will clarify a matter related to the reporting requirements for market based rates. Any change to the reports related to market-based rates must be clear, commonly understood and properly vetted by all interested parties prior to implementation. A supplemental notice will achieve that end.
Finally, a supplemental notice will cure any defects with the current notice of proposed rulemaking. A notice of proposed rulemaking must give the public adequate notice of the changes being proposed by the Commission. The notice must be clear and to the point. Given the vagueness of the original NOPR, were the Commission to issue in the final rule a detailed list of triggering events, the Commission might run afoul of the court’s concerns in Wagner Electric and McLouth Steel. For that reason, Professors Davis and Pierce recommend the issuance of a supplemental NOPR if there is a concern as to the adequacy of the NOPR vis a vis the changes actually proposed in the final rule. As they have said:
If an agency is concerned that the changes it needs to make in its final rule extend beyond the scope of its notice and therefore place its final rule in jeopardy of reversal under Wagner Electric, its only safe course of action is to issue a second notice of proposed rulemaking reflecting the nature of the changes it plans and to provide an opportunity for submission of comments on the second proposal.
Similarly, the D.C. Circuit has found that defects in the original notice may be cured by an adequate later notice.
D. Report Filings and Timelines
In response to the Commission’s inquiry on the timing of the reporting requirement, EPSA appreciates that the Commission is interested in receiving information more frequently than in the triennial market power analysis updates. However, to lessen the administrative burden on market participants, EPSA proposes that any and all changes be reported concurrent to the filing of public utilities’ Electronic Quarterly Reports (EQRs), allowing applicants a minimum of 30 days and no longer than 120 days to file a notice of change in status. It is reasonable that the timeline set up for the EQRs will be adequate for vigilant oversight of market-based rate sellers. The status change reports will not be filed as part of the EQRs, but as separate, stand-alone transmittal letters with the same filing due date. Both filings do, however, enable the Commission to oversee markets, market sales and market situations, and enhance the Commission’s ability to gather adequate market information.
One question that remains, however, is when, in the life of an event, a proposed change may trigger the reporting requirement. This question holds equally for the purchase or construction of generation facilities as it does for entrance into a long-term power purchase agreement (PPA) that involves a change in ownership or control of generation assets. However, the timing does not hold equally for the different types of events. The triggering event for an acquisition could either be when the asset acquisition contract is executed, when the Hart-Scott-Rodino filing is made, or when actual financial closing is achieved. For a greenfield development project, or even the repowering of an existing facility, the triggering event could be announcement of the project, announcement of executed PPAs, if any, associated with the project, receipt of the necessary air, water and land use permits, execution of an interconnection agreement, completion of financial closing, notice to proceed on actual construction, or even a specified period of time in advance of commencement of commercial operations. The triggering event for a sales contract for capacity, energy, ancillary services or full requirements for a period of more than one year could be announcement of the contract or a specified period of time in advance of when power begins to flow under that contract. Clearly, more clarity is needed from the Commission on these questions in order to provide certainty.
Just as clearly, many, if not most, of the applicants to and holders of market-based rate authority would prefer to have discretion within these multiple milestones to make the determination as to when to report the triggering event. The key for the Commission should be that there is an opportunity for review of the transaction and its impact on the market before the power flows. Resolution of these timing issues should occur in the supplemental NOPR recommended herein, whereby the comments in this NOPR and in the supplemental NOPR can be considered by the Commission.
As another clarification, the Commission should note that some transactions or triggering events may be of sufficient scope to require detailed and time-consuming analysis by the applicant. When this is the case, the Commission should accept an initial filing to report the event, particularly if the 30-day reporting requirement proposed in the NOPR is retained, but grant the applicant requested additional time to complete necessary data and analysis, as may be outlined in the initial filing. This scenario should serve to appropriately notice material events in a timely manner while allowing for sufficient detail and supporting work to be included for thorough review by the Commission.
E.Comprehensive Market-Based Rate Authority Proceeding (Docket No. RM04-7)
The comprehensive proceeding, Docket No. RM04-7, will establish the permanent criteria on which the conveyance of market-based rate authority will be determined, and is correctly focused on reliance on all four prongs of the Commission’s market power analysis. The Commission proposes in the instant proceeding to “modify market-based rate authority of current market-based rate sellers to include the requirement to timely report to the Commission any change in status that would reflect a departure from the characteristics the Commission relied upon in granting market-based rate authority.” While this language appears to be straightforward, it may be confusing in light of the current examination of the analytical methods and criteria to be used to assess markets and market power in Docket No. RM04-7. In the order initiating Docket No. RM04-7, the Commission states,
…currently there are no comprehensive codified regulations governing what applicants must demonstrate in order to obtain market-based rate authorization from the Commission. Much has changed in the industry since the Commission began using the four-prong test in the 1980s, and we believe it is important not only to ensure that our test is sufficient to support market-based rates in today’s energy markets, but also to provide clarity, by way of codified regulations, as to what applicants must demonstrate in order to obtain (and retain) authority to sell at market-based rates.
As has been noted in the above statement, the precise factors relied upon by the Commission to grant market-based rate authority are not necessarily clear or obvious at this time. Though each company that currently has market-based rate authority made a showing that it passes the four prongs of the market power test, the precise characteristics of FERC’s determination are not self-evident. Hence, the reporting requirement for a change in status could become embroiled in similar ambiguity.
EPSA is concerned that this ambiguity could remain until resolution of the generic proceeding in Docket No. RM04-7. Certainly, the reporting requirements must be an aspect of the overall approach to market-based rate authority. At some point, any standards or language developed in the instant proceeding must be rolled in to a final rule issued in Docket No. RM04-7. With this in mind, the Commission should act in the instant proceeding, noting that specifications of the reporting requirements may shift in the future as part of the standards developed and adopted in the comprehensive proceeding.