Order No. 697-A

 

On April 21, 2008 the FERC issued Order No. 697-A, addressing issues raised on rehearing of Order No. 697.

In the Rehearing Order FERC for the most part affirms the key elements of Order No. 697. There are, however, several important changes and clarifications. These include:

. • Adoption of a new protocol on import allocation that could increase the fre­quency and scope of screen failures.

. • Providing greater predictability on the consequences of screen failures by rejecting proposals to include “must offer” provisions in the default mitiga­tion package.

. • Establishing a rebuttable presumption that Regional Transmission Orga­nization (“RTO”) market rules are adequate to address screen failures.

. • Providing a path for MBR sellers to obtain MBR authorization for specific, long-term power purchase agreements in mitigated markets.

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. • Replacing the “two-way” information sharing restriction under the affiliate rules with a “one-way” restriction, thereby allowing communication of mar­ket information from market-regulated affiliates to franchised utilities.

Horizontal Market Power

Under Order No. 697, a party with MBR authority must submit two indicative screen analyses when it files a market power study update or a material change in status fil­ing. These screens are (a) a wholesale market share analysis, which is satisfied if the seller (including all of its affiliates) has an uncommitted capacity market share of 20 percent or less in each season in the relevant geographic market(s) where it makes sales and (b) a pivotal supplier analysis, which is satisfied if market demand in the relevant geographic mar-ket(s) can be served without any contribution of supply by the seller (including all of its affiliates).

The Rehearing Order affirms most of the principal determinations in the Final Rule concerning the horizontal market power screens:

. • The Commission affirms the use of a 20 percent threshold for the market share screen. That threshold had been challenged by many non-RTO utilities whose screen failures trig­gered the loss of MBR authority in their balancing authority markets.

. • The Commission rejects a number of arguments seeking to modify the design of the indica­tive screens, including an argument that “contestable load” is the relevant measure of wholesale load potentially affected by market power.

. • The Commission affirms its prior decision to use a seller’s balancing authority area, RTO region, or previously designated submarket as the default relevant geographic market (but reversed itself on designation of “PSEG North” as a PJM submarket). The Commission also left open the option of designating additional RTO submarkets based on internal trans­mission constraints.

. • The Commission affirms the requirement to submit a Delivered Price Test (“DPT”) analy­sis if a seller is seeking to rebut a presumption of market power in the event of indicative screen failures. This includes the use of a 2,500 HHI threshold for the DPT analysis.

. • The Commission affirms use of average peak native load as the native load proxy for the indicative wholesale market share screen and DPT-based screen analysis. This is a key issue in the determination of “uncommitted capacity.”

While affirming the key elements of the horizontal screens, the Rehearing Order contains several important changes and clarifications in the rules governing how the screen analysis is to be pre­pared. One of the most significant policy changes (which the Commission states is a clarification), is that transmission import capability based on SIL Studies first should be allocated to the seller’s uncommitted generation in first-tier markets, with any remaining capability then allocated to any uncommitted competing supplies. Prior to this clarification most practitioners understood the rules to allow for allocation of the SIL on a pro rata basis. Under the new allocation protocol there is an increased risk of screen failures for traditional utilities in both non-RTO markets and in certain RTO submarkets, as well as the possibility of new screen failures for some utilities in first-tier mar­kets. We believe this change or clarification will be subject to further litigation given its potential impact on MBR sellers.

The Commission also clarifies that a seller can consider long-term sales (one year or longer) when calculating its uncommitted capacity. The Commission similarly finds that generation capacity committed to a competitor’s native load or otherwise unavailable for sales on a long-term firm basis will not be considered available to compete with a seller’s generation. Accordingly, that generation will not be included as available economic capacity in a supplemental DPT analysis.

The Commission affirms the use of an historic “snapshot-in-time” test year for preparing the indicative screens (based on seasonal rather than calendar quarters). The Commission, however, appears to have further opened the door for parties to argue that some known changes should be considered under specific facts. This could be a significant concern for companies that either are making major new capacity additions or anticipating the termination of major power sales. It also continues the existing disconnect between market power studies undertaken pursuant to Section 203 of the Federal Power Act (“FPA”), which must consider changes in market power based on a future test year, and market power studies associated with MBR authorizations.

Finally, FERC declines in the Rehearing Order to provide much additional guidance or any form of bright line test regarding the circumstances under which contractual rights will be deemed to confer “control” over generation. The Commission instead reiterates the generic criteria that should be used to analyze a contract. The Commission affirms that, when addressing this issue in filings with the Commission, sellers should state specifically whether or not a contractual arrange­ment transfers control, the basis for that determination relative to the Order No. 697 criteria, and the identity of the party or parties it believes control(s) the relevant generation. We note that in a separate order FERC recently ruled that firm-liquidated damages contracts under the EEI master agreement do not convey control.

Vertical Market Power

Parties submitted only limited requests for rehearing regarding vertical market power and barriers to entry (which were combined in the Final Rule into a single “vertical” market power prong under the revised MBR criteria). In the rehearing order, the Commission denies those requests for the most part, although the Commission does grant some clarifications.

In what is perhaps the most important issue for transmission owners and their affiliates with MBR authorization, FERC rejects arguments that a transmission owner that has violated its open-access transmission tariff (“OATT”) automatically should lose MBR authority, or that such a violation should at least create a rebuttable presumption to that effect. The Commission instead reaffirms its decision to consider that issue on a case-by-case basis.

The Commission also clarifies that a seller does not need to report its ownership of financial trans­mission rights (“FTRs”) as part of a vertical market power assessment. To the extent there is a question of potential market manipulation related to FTRs, the Commission will address the issue through an Office of Enforcement proceeding.

Finally, the Commission clarifies that, when reporting ownership or control over inputs to electric power production in a change in status filing, a seller need only disclose changes in control or own­ership over physical coal sources or access to coal transportation via barges and rail. It is not nec­essary to report coal supply contracts or leases of barges or railcars when those leases do not restrict access.

Market Power Mitigation

A seller failing the indicative screen and choosing not to file DPT-based screens continues to have the option of either (a) accepting default (cost-based) mitigation or (b) submitting some form of “customized” mitigation for sales in the relevant geographic market(s). The Commission notes, how­ever, that the indicative screens and the DPT employed in the horizontal market power analysis focus only on short-term markets. In other words, absent barriers to entry long-term markets are pre­sumed to be competitive. Consistent with that policy, FERC revises the approach under which it generically mitigates long-term (one year or longer) transactions where the horizontal market power analysis resulted in a finding of market power.

Specifically, an otherwise mitigated seller may submit a filing under Section 205 of the FPA requesting market-based rates for a long-term contract if the seller can demonstrate that it lacks market power with respect to that specific contract. The Commission will not require any specif­ic type of evidence in support of such an application, but encourages sellers to identify “a specif­ic buyer for a proposed contract” to help the Commission understand that particular buyer’s supply alternatives and purchase options at the time the contract was negotiated. A seller may include information relating to third-party market entry, newly constructed resources during the relevant period, or the buyer’s self-build options as alternatives to purchasing under the contract at issue.

The Commission again rejects calls for an across-the-board “must offer” requirement for mitigat­ed sellers. A number of parties (particularly smaller wholesale customers) argued that such a requirement is needed for cost-based sales to assure that buyers located in mitigated markets will continue to have access to “low-priced” supplies. These parties argued that low-priced power oth­erwise may be diverted by MBR sellers to unmitigated markets. The Commission finds that, although proponents of a must offer requirement raised a theoretical concern, they failed to pro­vide evidence in support of their position. The Commission, however, expressly confirms that it has not “pre-judged” whether a must offer requirement should be imposed on a particular seller under particular facts.

In response to proposals linked to the “must offer” issue, FERC rejects the notion that market-based rates should be denied in first-tier markets based on a failure of indicative screens in the sell-er’s balancing authority area. In related matters:

. • The Commission rejects arguments that sellers should be permitted to make MBR sales within the balancing area in which the seller has market power if the buyer’s load sinks in a non-mitigated balancing area. The Commission rejects this proposal in part because of the difficulty of monitoring such sales.

. • The Commission agrees to modify the standard tariff language for a mitigated seller that makes sales at the metered boundaries of a balancing authority area in which the seller is subject to mitigation. The Commission also clarifies that it does not matter on which “side” of the metered boundary the sale technically is made, provided that “the Seller and its affiliates do not sell the same power back into the balancing authority area where the seller is mitigated.” This new language replaces tariff language previously adopted in Order No. 697, which included an “intent” component. These changes to the standard MBR tariff language are to be incorporated the next time a seller otherwise is required to submit revised tariff sheets.

. • The Commission clarifies that the revised tariff language on border sales for mitigated sell­ers is intended to prohibit so-called “sleeve” transactions. In a sleeve transaction, a miti­gated seller sells power to an unaffiliated third party, that unaffiliated third party sells the power to an affiliate of the mitigated seller, and the affiliate then re-sells the power back into the mitigated market. Regardless of whether such a series of transactions is

“pre-arranged” or “coincidental,” it is prohibited. Neither mitigated sellers nor their affiliates may sell power at market-based rates in the balancing authority area in which the sell­er is found or presumed to have market power.

Another key item the Commission addresses with regard to market power mitigation is whether to apply default mitigation in the event of screen failures in RTO markets or submarkets. The Commission adopts a rebuttable presumption that Commission-approved RTO market monitoring and mitigation rules are sufficient to address market power concerns in RTO markets, including mitigation applicable to RTO submarkets. This finding eliminates the need for sellers to argue in each case why existing mitigation is sufficient to overcome screen failures. The Commission states, however, that it will continue to provide an opportunity for parties in MBR proceedings to show that additional mitigation is needed in the event of screen failures within an RTO. Notably, the Commission also states that “if existing mitigation is found to be inadequate for a particular seller, then it is likely to be insufficient for all similarly situated sellers” (emphasis added). This language suggests that it could be difficult to sustain an argument for imposing default (cost-based) mitigation within an RTO, given the disruptive effect such remedial action likely would have on overall market operations.

Affiliate Restrictions

In the Rehearing Order, FERC makes a significant change with respect to the rules governing information sharing between market-regulated sellers and affiliated franchised utilities, changing from a “two-way” restriction to a “one-way” restriction. This means that companies only will be required to prohibit communications of market information from a franchised public utility with captive customers to a market-regulated power sales affiliate (where such sharing could be used to the detriment of captive customers, and the information is not simultaneously disclosed to the pub­lic). However, communications in the other direction — i.e., from a market-regulated power sales affiliate to a franchised utility with captive customers — no longer are prohibited outright. The “one-way” restriction will be familiar to many, as it was commonly (though not universally) employed before FERC adopted a “two-way” restriction in the course of codifying the affiliate restrictions last year in Order No. 697.

While relaxing the information sharing provisions of the affiliate restrictions, the Commission states that it will exercise its statutory authority to punish any undue preference that may arise from communications that are not expressly prohibited by the rules: “we remind all market-based rate sellers that the FPA prohibits any seller from providing an undue preference to an affiliate or any other seller.” Thus, companies considering whether to restructure their compliance programs in light of the change to a one-way restriction should also consider the corresponding risk that a com­munication from a market regulated power sales affiliate to a franchised utility could violate the FPA’s undue preference prohibition.

The Rehearing Order also provides the following guidance and clarifications with respect to a num­ber of key elements of the affiliate restrictions:

. • Power Sales Between Franchised Utility Affiliates. No additional authorization is required for power sales between two franchised public utilities with market-based rates, even if one has captive customers and the other does not.

. • Prior Codes of Conduct Partially Superseded. The Rehearing Order provides that in the event of a conflict between a seller’s code of conduct approved before the Final Rule took effect and the newly codified affiliate rules (included in Section 35.39 of the Commission’s Regulations), the new Regulations apply. However, when in a particular case the Com­mission imposed specific limitations more restrictive than those codified in Section 35.39, such limitations will remain in effect. Based on several examples FERC provides in the Rehearing Order, it appears that a more restrictive provision will continue to apply only if it was targeted to the entity in question, as opposed to being a more restrictive provision of general applicability that was overturned in Order No. 697. However, this point remains somewhat unclear.

. • Captive Status of Wholesale Customers. The Commission will consider on a case-by-case basis requests to determine that wholesale customers are not “captive” customers, or oth­erwise cannot be harmed by affiliate interactions.

. • Captive Status of Retail Customers. A state commission in a retail choice state may file a peti­tion for declaratory order or intervene in an MBR proceeding, if the state believes that retail customers are not “sufficiently protected,” such that the retail customers should be deemed captive customers and the affiliate restrictions should apply. The Commission made a paral­lel determination in the recently adopted Affiliate Transaction Rule (Order No. 707).

. • Recording Affiliate Waivers In Tariff Sheets. If a seller has been granted a waiver of the power sales restrictions or other affiliate restrictions (formerly referred to as the Code of Conduct), the waiver must be cited using a citation form provided in the Rehearing Order. If a seller desires to seek waivers in a new filing, the Rehearing Order provides a new mechanism for obtaining a docket number in advance, so that the docket number can be cited in the “Exceptions and Limitations” section of the proposed tariff sheets. If the Commission then grants the waivers, no further compliance filing will be needed to amend the tariff to identify the order granting the waivers.

• Field and Maintenance Employees. Field and maintenance employees eligible to be “shared employees” include technical and engineering personnel engaged in generation-related activities, provided that such employees do not themselves (a) buy or sell energy,

(b) make economic dispatch decisions, (c) determine (as opposed to implement) outage schedules, or (d) engage in power marketing activities.

. • Risk Management Personnel. Risk management personnel are eligible to be shared employees “so long as they are acting in their roles as risk management personnel rather than as marketing function employees, as defined in the Standards of Conduct.” Interestingly, the current FERC Standards of Conduct do not define either “risk manage­ment personnel” or “marketing function employees,” though the rules do permit sharing of “risk management employees that are not engaged in Transmission Functions or sales or com­modity functions.” However, the March 21, 2008 notice of proposed rulemaking on Standards of Conduct does propose a definition of “marketing function employees.” Thus, it is not exact­ly clear whether FERC is referring to the existing Standards of Conduct or the proposed new Standards of Conduct. However, treatment of risk management personnel under both the existing and the proposed new Standards of Conduct appears generally similar.

. • Historical Market Information. The definition of market information will continue to include historical information.

. • Service Company At-Cost Pricing. Pricing for non-power goods or services that complies with Order No. 667 — which generally authorizes the use of at-cost pricing by a central­ized service company for sales of non-power goods and services to utility affiliates, absent any demonstration by a complainant that such pricing exceeds the market price — fits within the “unless otherwise permitted by Commission rule or order” exception to the asymmetrical pricing requirements for non-power goods and services.

. • Use of Fully-Loaded Cost. The Commission will address in a subsequent order a request for clarification that the affiliate restrictions permit provision of non-power goods and ser­vices to an affiliate at fully-loaded cost. Such a rule would be comparable to non-power goods and services that are provided by a centralized company.

. • Definition of Affiliate. The Commission will use the same definition of “affiliate” for the affiliate restrictions as is now used in the Affiliate Transactions Rule (Order No. 707).

Change in Status Reporting

The Commission affirms the requirements, initially codified in Order No. 652 and revised in the Final Rule, for sellers to report any change in status (“CIS”) that departs from the characteristics relied upon by the Commission in authorizing MBR sales. While in Order No. 697 FERC estab­lished two categories of sellers with MBR authorization, the smaller of which (Category 1 sellers owning less than 500 MW) is exempt from triennial reviews, both categories must adhere to the Commission’s CIS reporting requirements. When submitting a CIS report, an MBR seller must explain what effect, if any, the triggering event has on its market power. A seller that files a CIS report and makes an affirmative statement that there is no effect on its market power is bound to that state­ment. Such a seller faces remedial action, including civil penalties, for any misrepresentations.

FERC rejects proposals to require MBR sellers to automatically file an updated market power analysis with their CIS filings. Given the wide range of events and low threshold (e.g., increases of 100 MW in generation) that might trigger a CIS filing, such a requirement would have imposed enormous time and resource burdens on many MBR sellers.

Implementation Issues

In the Rehearing Order, FERC affirms the two-tiered reporting scheme for MBR sellers established in the Final Rule but provides several clarifications to assure adequate oversight of Category 1 sell­ers. For example, while continuing the Category 1 exemption from the requirement to file updat­ed market power studies, FERC makes clear that the exemption is not automatic. A seller instead must make an initial filing to establish its exempt status. FERC also reminds Category 1 sellers of their continuing obligation to file CIS reports should their circumstances change. The Commission notes that the Office of Enforcement will conduct ongoing monitoring and audits of entities claim­ing Category 1 status. Commission Staff also periodically will conduct its own analyses of possi­ble market power concerns related to any Category 1 seller (e.g., in relation to newly designated submarkets wherein smaller generation holdings could be problematic), and may require the sub­mission of additional market power update studies by such a seller notwithstanding its initial exemption.

In the end, any change in overall market conditions, as well as any change by a Category 1 seller’s circumstances, may jeopardize Category 1 status. It thus will be important, when undertaking changes or pursuing commercial opportunities, to consider the likely effect of such changes on Category 1 status and the additional reporting burdens that could result from regularly scheduled market updates under Category 2.

Another noteworthy aspect of the Final Rule relating to implementation is the Commission’s deci­sion to deny rehearing requests objecting to the new consolidated regional filing approach for sell­ers in six designated regions. While acknowledging that it may be more efficient (from a compa-ny’s standpoint) to prepare and file a single multiregional triennial study, FERC states that such an approach would not satisfy the agency’s desire to ensure greater consistency in the data used to evaluate sellers’ market power in each region (the primary driver for the new approach) and to rec­oncile conflicting submissions. Larger companies with MBR sellers in more than one region there­fore will have to file multiple market updates based on the new regional schedule.

Under the regional filing schedules included in Order No. 697, “transmission operators” were required to file their updated market power studies six months prior to other sellers in that market. The Rehearing Order contains a revised Appendix D schedule clarifying that the term “transmis­sion operators” refers to transmission-owning utilities with MBR authority and their affiliates. However, there has been considerable confusion (and an extensive Commission request for addi­tional SIL-related data from transmission-owners) in the initial round of market power filings in the PJM market. This has highlighted the need for additional guidance on the overall issue of SIL studies used to prepare market power screens, and may result in further modifications to the filing rules and schedules.

FERC provides several procedural clarifications regarding filing requirements under the revised regional filing schedule:

. • A seller requesting Category 1 status must file such a request at least 120 days prior to the first day of the month in which its next updated market power analysis is due.

. • If an unaffiliated power marketer requesting Category 1 status has made no sales since its original MBR authorization, it should make its waiver submission during the next sched­uled filing period. Once FERC determines that a seller is in Category 1, that seller will not be required to file updated market power analyses, or evidence of Category 1 status, for the other regions in which it makes sales so long as it continues to meet the criteria for a Category 1 seller.

. • The electric transmission facilities that must be included in the new Appendix B “asset matrix” are limited to those for which ownership or control would require an entity to have an OATT on file with the Commission — even if the Commission has waived the OATT requirement for a particular seller. Also, FERC clarifies that in preparing Appendix B companies may aggregate transmission line miles of common voltage facilities rather than having to list individual lines.

. • Sellers must submit both the generation and transmission/pipeline portions of the asset appendix, even if the seller has no assets to list in a specific section.

MBR Tariff Sheet Language and Filing Requirements

In Order No. 697, FERC required MBR sellers to modify their existing tariff sheets to incorporate certain standard language. When it first files a triennial update, a CIS report, or an amended tar­iff, each seller must include standard language certifying compliance with Subpart H of Part 35 of the Commission’s Regulations, making failure to adhere to these regulatory requirements a tariff violation. FERC also directed each seller to list all limitations on its MBR authority (including markets where the seller does not have such authority) and any exemptions, waivers, or blanket authorizations FERC has granted the seller. The Commission did not, however, provide much guid­ance on the format of these tariff notations. This has resulted in a number of deficiency letters from Staff since the new tariff language was deemed effective (September 18, 2007, the effective date of the Final Rule).

In the Rehearing Order FERC clarifies that a corporate family may adopt a single tariff filing date for all affiliated MBR sellers, presumably at the time of the first applicable compliance filing date applicable to any of the entities. However, companies still must adhere to the Appendix D sched­ule for market power updates. FERC also provides additional clarifications and procedural guid­ance concerning new and amended MBR tariffs:

. • All provisions that were contained in a seller’s previous MBR tariff but are now codified in Subpart H of the Commission’s Regulations (for example, the old Codes of Conduct and the affiliate power sales restrictions) must be removed from the tariff. Tariffs can, howev­er, include “seller-specific” terms and conditions typically found in power sales agree­ments, such as provisions on creditworthiness, force majeure, dispute resolution, billing, and payment.

. • FERC adopts minor changes to the Order No. 697 standard tariff language for third party providers of ancillary services, making the provision consistent with the RTO-specific ancillary service language. The Commission also clarifies that, to the extent a seller with MBR authority does not presently have authority to make market-based sales of ancillary services, the seller may file revised tariff sheets, including the standard applicable provi­sions from Appendix C, without seeking separate Section 205 authorization.

. • Each set of tariff sheets must now include the seller’s status as either a Category 1 or Category 2 seller using standardized language provided in the Rehearing Order.

Legal Authority for MBR Program

In the Rehearing Order, FERC rejects several legal challenges to the MBR program. For example, the Commission rejects arguments that it lacks authority to adopt market-based rates and that its MBR procedures fail to comply with the notice and filing requirements of Section 205 of the FPA. The Commission also rejects arguments that (a) the MBR program unlawfully shifts the burden of proof under Section 205, (b) FERC was required to find the existing MBR tariffs unjust and unrea­sonable under Section 206 and establish a refund effective date, and (c) MBR tariffs violate the require­ment that utility rate schedules be on file and the prior notice and filing requirements governing rate increases. The discussion of these legal challenges is extensive, covering nearly 100 pages.