By Mike Tomsu, Kathleen Lake, Jamie Serota, Stephen Angle and Donna Bobbish
On July 31, 2002, FERC issued for public comment what promises to be the third installment of its restructuring trilogy: a notice of proposed rulemaking (NOPR) on Standard Electric Market Design (SMD). FERC concluded that, in spite of its two previous restructuring rules, Order No. 888 (which required that all public utilities provide open access transmission) and Order No. 2000 (which required all transmission providers to place their transmission facilities under the control of Regional Transmission Organizations (RTOs)), discriminatory transmission practices continue and inconsistent design and administration of short-term energy markets have resulted in pricing inequities that can cause unjust and unreasonable rates.
Now FERC proposes to: (1) establish a single open access tariff with a single transmission service applicable to the interstate transmission grid; (2) require all public utilities that own, control or operate interstate transmission facilities to become, turn their transmission facilities over to, or contract with an "Independent Transmission Provider" (ITP); (3) establish an access charge to recover embedded transmission costs based on a customer’s load ratio share of the ITP’s costs, (4) use locational marginal pricing (LMP) as the system for transmission management; (5) provide tradable financial rights -- congestion revenue rights (CRR), as a means of "locking-in" a fixed price for transmission service, (6) establish imbalance energy markets; (7) establish procedures to mitigate market power in the day-ahead and real-time markets, and mechanisms for market monitoring; (8) establish procedures to assure the maintenance of adequate transmission, generation and demand-side resources on a long-term, regional basis; and (9) provide a formal role for state representatives to participate in decisionmaking.
New Market Design
ITPs
Based on its conclusion that corporate ties between generation and transmission within public utilities allow vertically integrated utilities to exercise market power, FERC would require transmission service to be provided by an ITP -- a public utility that owns, controls, or operates facilities used for the transmission of electric energy in interstate commerce, that administers the day-ahead and real-time energy and ancillary services markets in connection with its provision of transmission services pursuant to the SMD tariff, and that has no financial interest either directly or through an affiliate, in any market participant in the region in which it provides transmission services or in neighboring regions. FERC would require that public utilities inform the FERC which ITP will operate the public utility’s transmission facilities no later than July 31, 2003.
FERC’s view that transmission service should be provided by an "independent" entity previously was expressed in Order No. 2000. In SMD, however, the FERC moves beyond RTOs in its prescription of the market functions to be performed by ITPs and governance requirements for ITPs. In addition to having responsibility for transmission system operation and planning, FERC would require ITPs to operate day-ahead and real-time energy markets to manage congestion by allocating transmission and generation capacity among competing uses in different markets through LMP pricing, and to create Market Monitoring Units (MMUs) to establish bid caps and "must offer" requirements.
FERC would require all ITPs to satisfy governance requirements, specifically: (1) the board of directors of an ITP must not be a stakeholder board with industry segments given specific seats; (2) board members must have no financial interest in market participants; (3) an ITP must have, at a minimum, advisory committees that reflect interests of generators and marketers, transmission owners, transmission-dependent utilities, public interest groups, alternative energy providers and end-use and retail energy providers; (4) an ITP must have a separate Regional State Advisory Committee (RSAC) to advise the board; (5) board candidates must have experience in one or more specified fields; (6) board members or their immediately families should not have current or recent ties as a director, officer or employee of a market participant in the region or its affiliates, and should not have direct business relationships with market participants or their affiliates; (7) a nationally recognized search firm should be retained by the nominating committee to identify candidates that satisfy the criteria; (8) a nominating committee composed of two members from each of the stakeholder classes would be formed to review the list of candidates presented by the search firm; and (9) board seats would be selected by a simple majority.
Network Access Service
FERC would modify its pro forma open access transmission tariff to establish a single, flexible transmission service, "Network Access Service," that applies to all transmission customers – including bundled retail customers. FERC would require ITPs to provide Network Access Service to all customers. Network Access Service would allow a customer to: (1) have the ITP integrate, dispatch and regulate the customer’s current and planned resources to service its load; (2) transmit power between any number of combinations of receipt and delivery points; and (3) trade its CRR and access points which, under the current pro forma tariff, are secondary points that may be fully subscribed.
FERC also would require ITPs to manage congestion using a system of LMP and CRR. Under LMP, the ITP would establish separate energy prices at each receipt and delivery point (node) on the transmission grid and separate prices to transmit energy between any two nodes on the grid, to reflect congestion. Under LMP, CRR would provide customers with price certainty for transmission service.
FERC would require that ITPs have in effect revised SMD tariffs and be operating under SMD by September 30, 2004.
New Transmission Rate Design
If implemented, FERC’s proposals regarding the pricing of transmission service and the planning of new transmission infrastructure should contribute significantly to the development of competitive national markets for wholesale electric energy. On the planning side, FERC calls for the creation of regional authorities that will be responsible for long range planning for transmission infrastructure additions. FERC envisions strong state PUC participation in this effort and envisages that these regional entities will assess and approve the transmission additions necessary to serve load growth and to support the increased transfer capacity that will be needed for expanded interregional trading.
FERC’s transmission pricing proposals are premised on a cost assignment policy for infrastructure additions that should produce broad-based support for new construction. FERC proposes to maintain its current policy that only the direct interconnection costs and costs of local area upgrades are directly assigned to new generators. It proposes a new policy with respect to high voltage transmission upgrades. The proposal has two options. One is that all upgrades to the regional grid at 138 kV or higher should be rolled-in and included in the rate base used to develop the general access charge. The second option is that these higher voltage facilities may be paid for by a specific user, with the user receiving the rights to receive CRRs associated with the capacity. In the instance where higher voltage upgrades are rolled-in, the CRRs for the capacity would, under the general rule for CRRs, be available for auction as otherwise uncommitted capacity. CRR auction revenues will be credited against the transmission cost of service.
FERC also suggests that some portion of the cost responsibility for transmission investment in net export regions may be transferred to net import regions. Ratepayers in exporting regions can be expected to oppose transmission investment in their region if they bear the cost. FERC also indicates its willingness to address revenue decreases that may also result from its elimination of transmission charges from wheels out-of or across transmission systems. Many existing transmission rates – both those that apply to unbundled wholesale transmission service and those implicitly contained in bundled retail electric service rates – have been developed based on projections of significant revenues from transmission service to extra-territory customers. Eliminating those revenues will both increase the costs to the remaining load and may, if retail rate freezes are in effect, have a significant effect on the bottom line for those entities that have traditionally provided large amounts of transmission service.
FERC also proposes to implement unitary transmission pricing for service over multiple ITPs in order to eliminate pancaked transmission rates. The governing principles are that (1) only load will pay the transmission access charge, and (2) the access charge will be based on the rate that applies in the service territory of the ITP where the load is located. ITP access charges may be zonal (varying by sub-regions of the ITP, usually reflecting the combination of historically distinct transmission systems) or postage stamp (designed to allocate the cost of service for combined systems uniformly to all customers taking service). Also, because all load (including existing bundled retail load taking service from an integrated utility) will take the same Network Access service, there will be no need to develop separate cost allocations for distinct service classes. All load will also be subject to congestion charges. Congestion charges will be due for deliveries in the ITP territory where the load is located. In addition, in order to assure delivery, the load may elect to be responsible for congestion related to deliveries across any other ITP(s) in the transmission path. The question of whether responsibility for congestion over other ITP(s), if elected, will be determined on a contractual path basis or a load flow basis is apparently open for discussion. The latter more closely conforms to the general principles of LMP pricing.
New Market Monitoring and Mitigation Measures
FERC’s NOPR would require that each ITP institute three mandatory components of market mitigation and would permit ITPs to propose a fourth optional component. Each ITP would also be required to establish an independent market monitor with responsibility for reporting directly to the ITP board and to FERC. Among its responsibilities, the market monitor will perform an initial competitive market analysis for the markets to operated by the ITP, which would be filed with FERC and made subject to comment. The analysis would be updated yearly. Market mitigation would be applied to spot markets for energy and ancillary services but would not be applied to bilateral contracts for such services.
The three mandatory requirements for market mitigation are (1) controls on locational market power, (2) a safety net bid cap, and (3) ensuring resource adequacy. FERC defines locational market power as the temporal ability of certain energy sources to demand, due to congestion limits on energy delivery, prices unconstrained by competition.
The existence of congestion-related locational market power – at least on a short-term basis - is generally conceded by economists. The issue is what measures to constrain the temporal exercise of such market power are consistent with and will support the development of wholesale markets. FERC’s proposal is that each generator must execute a participating generator agreement (PGA) with its ITP. The PGA would include a "must-bid" obligation and a bid cap that would apply when locational market power exists. Recent experience shows that these measures can create significant unintended effects. For example, the California ISO has used a provision in its standard form PGA that requires a generator to abide by the ISO’s FERC tariff to file unilaterally price terms that govern what a generator may charge during congestion related import limits.
FERC’s second mandatory mitigation is a safety net price cap, intended to prevent spiraling price escalation in response to extraordinary supply and/or demand conditions, such as was seen in California. FERC suggests that the cap of $1000 MW/hr, which has worked well in eastern markets, may be a good national standard.
The third mandatory mitigation is the imposition of a resource adequacy requirement. FERC’s objective is to limit the possibility that load serving entities will elect to enter into long-term service commitments without obtaining long-term supply arrangements. FERC expresses dissatisfaction with the use of "installed capacity" markets for this purpose. FERC notes that an installed capacity obligation does not insure capacity additions and may artificially inflate the value of older, inefficient generation. FERC’s solution, however, creates a governmental "command and control" response in which FERC proposes to require extensive reporting of load projections and to establish mandatory resource commitments.
As a fourth mitigation measure, FERC suggests that market monitors should be in the position to recommend default energy bid caps. This proposal is an endorsement of the automatic mitigation procedures (AMP) that have been in place in the New York ISO since its inception and have recently been adopted by the California ISO. The premise of AMP is that, by continually monitoring the level of bids and market outcomes, the market monitor can identify situations where "competition" is ineffective to limit prices and, consequently, "non-competitive" changes in market prices occur. Generally, this assessment is made by systematically comparing bid prices to "reference" prices. For instance, one formulation is that when bid prices increase by a certain percentage over "reference" prices and the effect on market clearing prices is to increase them by a predetermined amount (either a percentage or an absolute dollar amount), the bid is limited to the reference price. The bid amount may even be automatically reduced to the reference price, with the substitute reference price being used for purposes of applying the market clearing algorithm. This system is premised on substantial judgment, assumes that the exercise of that judgment will improve on market outcomes, and denies to the seller the certainty of a known price cap. Other discussion within the NOPR suggests that FERC is considering the establishment of a substantial regulatory program and staff, both within the agency and at the ITP left.
Market monitors will be able to propose additional mitigation measures, subject to FERC approval. FERC encourages the establishment of behavioral rules and penalties for market participants. The market monitor would have a duty to report all incidents of behavior to FERC that the monitor perceives to be inconsistent with the ITP tariff. As a condition to participation in markets, market participants could be required to agree to predetermined penalties applicable to violations of tariff rules.
New Roles for Regulators
SMD heralds a significant departure from the regulatory model historically followed in the U.S., in which the utility proposes rates or to construct facilities, or otherwise takes the initiative, and the regulator approves or rejects the utility’s proposal. Under FERC’s proposed rule, both FERC and state regulators assume a role in the day-to-day operations of public utilities and energy markets. In the NOPR, FERC concludes that ITP boards of directors should be responsible to FERC – not to market participants – for overseeing the ITP’s administration of the tariff and market rules and monitoring operation of the markets within its region to identify problems. According to FERC, an ITP board should ensure that instances of market power or market dysfunction are reported directly to the FERC by the MMU.
FERC also would establish a formal role for state representatives to participate on an on-going basis in the decision-making processes of ITPs and RTOs through Regional State Advisory Committees.
Issues and Questions
FERC’s ITP proposal signals its disenchantment with RTO formation and raises numerous implementation issues. The first of these is whether interested parties will challenge FERC’s legal authority to mandate ITP creation/participation. Also, in light of the fact that since Order No. 2000 was issued, only one RTO has become operational, how realistic is FERC’s deadline concerning compliance with its ITP requirements? What will happen if these deadlines are not met? FERC’s proposal also raises the question of who will form ITPs. Will many transmission-owning companies choose to transform themselves into ITPs, or will we see the formation of large companies whose only function is to operate a regional market? Will foreign companies enter U.S. electricity markets for the sole purpose of administering regional wholesale electricity markets?
The implementation of FERC’s plans for regional planning and cost allocation will require resolution of some difficult factual and legal issues. The most glaring is that FERC lacks direct authority to require regional planning as an integral feature of transmission siting. Thus, the state commissions that control siting will have to be convinced that it is in their interest to defer to regional decisions about the need for new transmission investment. The substantial displeasure expressed by numerous state commissions over FERC’s decision to require unbundling of retail transmission service and assert plenary rate and service jurisdiction over retail transmission makes this task more difficult. Obtaining agreement about transferring revenue responsibility among ITPs – whether to reflect the effects of additional investment to support exports or to address revenue shifts produced by the elimination of rate pancaking – is a formidable challenge. FERC may have little choice but to seek consensus, since its legal authority to transfer responsibility for costs between regulated service providers is unclear.
FERC’s market monitoring proposal, in essence, provides unfettered discretion to ITPs to set prices for generators in a significant number of instances. The FERC’s approach raises the issue of rate-setting authority under Section 205 of the Federal Power Act (FPA), which provides that the seller is entitled to propose rates, subject to FERC review. Furthermore, in providing non-profits the power to set the prices for sellers, FERC raises the question of its responsibility under the FPA to assure the propriety of bid caps. Even if the bid cap were subject to review and adjustment by a disinterested decision maker, the appropriate level for a bid cap is uncertain. Would the administrative burden of a process that would require FERC to review the propriety of hundreds of bid caps make effective FERC review unlikely?
Finally, FERC’s proposed new roles for regulators in wholesale energy markets raises the questions of whether states will accept the new roles FERC prescribes for them, and whether such federal-state involvement in the decision-making of public utilities will provide a disincentive to the formation of ITPs.
Initial comments on the NOPR were due no later than October 15, 2002.
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