Summary of the Federal Energy Regulatory Commission's Notice of Proposed Rulemaking on Standard Market Design

Summary

On July 31, 2002, the FERC issued a Notice of Proposed Rulemaking in Docket No. RM01-12-000, "Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design," generally referred to as the SMD Rule. Initial comments on the rule are due 75 days after publication. The proposed rule would require all public utilities with open access transmission tariffs (OATTs) to file modifications to those tariffs to conform to the mandates of the proposed rule. This proposed rules follows up on the redesign of FERC's regulation of the electric industry already begun with Order Nos. 888, 889 and 2000. These orders were intended to build regional transmission structures and to create and enhance competitive electricity markets. This NOPR is intended to remove the remaining impediments to those competitive markets, which it has identified as undue discrimination and lack of standardized tariffs, service provisions and rules. The draft rule also includes market monitoring and market power mitigation provisions.

To accomplish its objectives, the FERC proposes to assert jurisdiction over the transmission component of bundled retail transactions, in addition to wholesale transactions already subject to its regulation. It will also modify the pro forma transmission tariff to offer a single flexible transmission service called Network Access Service which will bring one set of rules to all transmission customers. Finally, the draft rule will provide a standard market design for wholesale electric markets. The FERC recognizes that its jurisdictional expansion to reach bundled retail transactions is opposed by many state public utility commissions and it has committed to working with the state commissions to effectuate this transition.

Network Access Service combines features of both existing network integration transmission service and point-to-point service. It will give the transmission customer the right to transmit power between any points on the transmission system provided it is feasible under a security-constrained dispatch.

While all transmission providers may not be members of RTOs initially, they will be obligated to contract with an independent entity to operate their transmission facilities until they have joined an RTO. An independent transmission provider (ITP) is defined in the rule as an entity with no financial interest, direct or indirect, in any market participant in the region in which it provides transmission services, or in neighboring regions. ITPs will administer the day-ahead and real-time markets as well as engage in long-term planning and expansions, system impact and facilities studies and transmission transfer capability calculations.

The SMD proposed relies on bilateral contracts between buyers and sellers, with a spot market intended to complement these arrangements. FERC proposes that the ITP operate markets for generation imbalances and ancillary services, as bid-based, security constrained spot markets operated both in the day ahead (of real time operations) and the real time markets. FERC is also proposing to adopt market-based locational marginal pricing for congestion management, which should allocate scarce capacity to those who value it most. It is also intended to send proper pricing signals to encourage both short-term efficiencies and long-term investment. Market participants would also be required to participate in a regional process to identify efficient and effective ways to maintain reliability and eliminate constraints. Congestion Revenue Rights will be established and can be used as a means to lock in a fixed price for transmission service.

The FERC proposes that an RTO or other regional entity must forecast the region's future resource needs, facilitate regional determination of adequate future resources, and assess the adequacy of the plans of load serving entities (LSEs) (which includes municipal utilities and electric coops) to meet regional needs. Each load serving entity must meet its projected needs through generation and demand reduction.

Basis for the NOPR: Need For Reform

FERC is legally obligated to explain the basis for its proposed rules. In the NOPR it found that additional measures are needed to achieve the goals of non-discriminatory transmission access and competition. Vertically integrated utilities use their transmission facilities to inhibit competition in both wholesale and open retail markets. New sellers who might be able to offer power at lower prices are kept out of the market. The absence of standardized market rules also creates opportunities for discrimination. "Seams" issues (differences between systems) also raise transaction costs and artificial barriers.

Transmission providers have exercised market power in various ways: using predicted load growth to prevent roll over of existing transmission contracts; delays in responding to service requests; scheduling advantages inherent in owning multiple generation plants; ability to resolve energy imbalances through in-kind exchanges; calculation of available transfer capability; manipulation of OASIS postings; reservations of excessive amounts capacity benefit margins (CBM); and dispatch of their own generation using transmission loading relief (TLR) procedures that curtail other services.

The need for standardized rules is seen in the advantages transmission-owning utilities have: network integration transmission service has advantages over point-to-point service; more flexibility enjoyed by transmission-owning utilities in designating receipt and delivery points; advantages in transfer capacity set asides for reliability; and favorable state curtailment rules.

The current congestion management system adopted under Order No. 888 does not result in use of the transmission system in the most efficient manner and customers are denied access to lower cost supplies that would be available if congestion management and pricing allowed the recovery of generator redispatch.

Proposed Remedies

• The transmission component of bundled retail service will be taken under an open access transmission tariff. The designated network resources that are used by the integrated utility will be used in converting service for retail load. The existing level of service would be provided under the new Network Access service and the load-serving entity or retail customer would receive Congestion Revenue Rights or auction revenues for these rights for the currently designated resources. In the interim, bundled retail load would be placed under the existing pro forma tariff, as it will be amended.
• Transmission service must be provided by an independent entity. All transmission providers must meet the definition of ITP, turn the operation of the transmission facilities over to an RTO that meets the definition of an ITP, or contract with an ITP to operate its facilities. An ITP would file a SMD tariff to provide transmission and ancillary services, administer the day-ahead and real-time markets and will also perform market monitoring and market power mitigation functions, long-term resource adequacy and transmission planning and expansion on a regional basis. The ITP will file for rate changes.
• Independent Transmission Company for-profit (ITC) model can bring significant benefits: improved asset management, improved access to capital, innovative services, and independence from market participants. The FERC seeks comment on whether an ITC can act as an ITP or whether it retains the ability to discriminate against other entities.
• ITPs would be required to offer a new transmission service called Network Access Service (NAS) which offers the flexibility of network integration service but has reassignability like that under firm point-to-point service. All customers will have the opportunity to acquire Congestion Revenue Rights (CRRs) which expand their transmission options. Congestion will be managed with Locational Marginal Pricing (LMP). The ITP will administer the spot market to manage congestion as well and also to handle imbalances and ancillary services. The ITP will operate markets for energy, regulation, operating reserve - spinning and operating – supplemental. These markets would be security-constrained, bid-based markets operated in day ahead and real time and transmission services would be scheduled day ahead and real time. The scheduling process must accommodate bilateral contracts.
• NAS allows the load-serving entity to serve its load with any available resource on the system or any interface. NAS can integrate, dispatch and regulate the customers' current and planned resources to serve its load and can also use it for through-and-out service, to aggregate resources for resale and to perform hub-to-hub transactions. NAS also allows the customer to trade its CRRs and to access points as secondary point by paying all applicable congestion charges. Where there are transmission constraints, LMP will price out all transactions and redispatch available generation as needed to accommodate all requests. All customers will pay congestion costs and losses but only customers taking power off the grid would pay access charges.
• Under NAS, all customers who want service that is physically feasible will be able to receive service, the uncertain element will be price (under the current scenario, pricing is certain, but availability of service is not). Embedded system costs will be recovered through the access charge and customers will also be subject to paying the cost of congestion between receipt and delivery points. To achieve price certainty and avoid congestion costs, the customer can acquire CRRs associated with a particular receipt-delivery point combination. CRR paths are scheduled in the day-ahead market. A customer can also cap the amount of congestion cost it is willing to pay. No separate non-firm service option is needed.
• Customers must execute contracts to receive NAS and meet existing requirements (creditworthiness, operating standards, etc). LSEs would also have to execute a network operating contract to detail how the ITP would work with the LSE' system.
• Congestion Revenue Rights can be acquired through direct allocation based on historic or current rights to the system, periodic auctions, secondary markets or a combination of these. Transmission service is scheduled in the day-ahead market with deviations accounted for in the real-time market. The customer would be liable for any redispatch costs that incur in real time to cover differences from the day-ahead schedule.
• NAS customers do not have to designate network resources in order to get transmission service. The NOPR contemplates that CRRs can be turned in and traded for other receipt and delivery point combinations, although the exact methodology for accomplishing this has not yet been determined.
• Load shedding and curtailment procedures will be included in the SMD tariff. ITP should be able to assess a penalty for failure to curtail after reasonable notice. The penalty would be the LMP plus $1000/MWh. Minimum notice period is 10 minutes.
• Transmission owners can recover their revenue requirements through either a license plate rate (charge depends on zone of delivery) or a postage stamp rate (same rate for all load in service area) and would be paid by all LSEs in that ITP's service area. It would be based on the LSE's respective share of the system's peak load (load ratio shares). All rate pancaking would be eliminated. Assessing the access charge primarily to LSEs based on their load ratio share rather than on the number of service areas over which energy is transmitted increases generation competition. Customers paying access charges would receive CRRs or revenues from the auction of CRRs. The Commission proposes that CRRs (and access charges) follow the "load" in states with retail access, and are assigned to new LSEs.
• NAS would eliminate payment of multiple access charges so that export and through-and-out transactions originating in an ITP's system and terminating at a load in another ITP system would pay only the access charge for the system where power is ultimately delivered to the load. However, exempting through-and-out transactions to avoid access charges in the originating ITP could lead to cost-shifting to load in that ITP area. Two approaches to solve this problem are suggested. One is to have the "source" ITP allocate a portion of its revenue requirement to the "sink" ITP's transmission customers. The other is to have a revenue crediting approach which prices inter-regional transfers at the load ratio share charge and the inter-regional transaction charges would be netted out over a time period. Charges would be assigned to all customers within the sink ITP.
• Lack of new transmission is a problem leading to more congestion. FERC proposes than expansions for region-wide reliability should be paid for by all ratepayers and interconnection facilities should be paid for by interconnecting generator, as is current practice. Economic expansions that would remove congestion and allow customers to access more distant supplies could be funded by participant funding, meaning those who benefit from a particular project would pay for it. The ITP could determine the cost and responsibility for the needed upgrades, the congestion pricing signals to which the customer responds and CRRs, and assumptions underlying the power flow analysis. In the absence of an independent system, FERC would apply a default pricing policy that recognizes the regional benefits of expansions. Costs of all high voltage network upgrades could be rolled in on a region-wide basis, and allocated to the region that benefits from the expansion, which may not be the region in which it is located. The Regional State Advisory Committee can be part of this process.
• A new congestion management system would require that all ITPs allocate scarce transmission capacity using a pricing system incorporating LMP and CRRs. Under LMP, the price to transmit energy between any receipt point and delivery point reflects the marginal cost (including the marginal opportunity cost) of such transmission service and the price of energy at each location reflects the marginal cost of producing energy and delivering it to that location. Under LMP, all suppliers selling at a location receive the market clearing price, even if they offered to sell for less and this is what FERC proposes. Under LMP, the ITP establishes separate energy prices for each node on the grid and separate prices to transmit energy between any two nodes. Economic redispatch will manage congestion. For customers buying energy under bilateral contracts, the transmission usage charge would reflect the marginal cost of transmission between a receipt and delivery point. That would be the difference between the LMP at the receipt point and the delivery point.
• Customers may make changes in transmission service in the real time market, different than what they scheduled in the day-ahead market. The customer would either sell back or purchase the capacity in the real time market. No congestion revenues are paid to CRR holders for transactions made in the real time market.
• Real time markets will be operated by the ITP to resolve energy imbalances. The imbalance is the difference between the energy scheduled on a day-ahead basis and the amount it takes off the system on a real-time basis. The price of the real time energy is set by a security-constrained, bid based energy market. Operating the day-ahead energy market will allow the ITP to manage congestion in the day ahead scheduling process. This is also a bid-based market, with sellers submitting bids for the amount of power they will offer for sale each hour of the next day and each node. Buyers also submit bids, including maximum prices. Parties will also be allowed to submit purely financial bids, bringing the prices of the day ahead and real time markets closer together. The day-ahead market is binding on all parties.
• FERC proposes that there be several types of CRRs, but will only mandate receipt point-to-delivery point obligation rights at this time and later expects point-to-point option rights and flowgate rights. The receipt point-to-delivery point right entitles the holder to the day ahead congestion revenues associated with transmission service between those points (but if using the path, the CRR holder must still pay congestion charges). When service cannot be provided with ATCs, CRR holders get priority over others in scheduling service between their designated points. Flowgate refers to a particular transmission facility or group of facilities (interface) and a flowgate right specifies a portion of the transmission capacity over that flowgate in a specified direction, entitling the holder to day ahead congestion revenues associated with power flow over the flowgate in the specified direction. A holder of flowgate rights is never required to make congestion payments.
• There may be revenue shortfalls associated with CRRs and congestion costs where the ITP collects less revenues from congestion charges than it owes to CRR holders. FERC proposes to assign the shortfall to the transmission owner, except for force majeure events, to reward them for proactively maintaining their systems.
• FERC desires an active secondary market for CRRs, which can be handled bilaterally or through auctions held by the ITP which provides greater pricing transparency.
• There are two ways, if not more, to arrange transmission service across borders of adjoining ITPs: physical reservations and scheduling service consistent with NAS transactions (scheduling transmission and financial bidding). FERC proposes to use the same method as proposed for intra-ITP transactions, a customer could either schedule transmission service and agree to pay the transmission usage charge regardless of the cost, or submit a bid that limits its congestion exposure.
• At the request of market participants, the ITP will establish trading hubs, which are virtual locations where financial transactions are arranged and which set a hub price at the weighted average of energy prices at a specified set of nodes on the transmission system. Zones may also be established that reflect the weighted average of energy prices at selected delivery nodes on the system.
• The ITP may offer, but is not the only source, for four ancillary services: regulation and frequency response; energy imbalance; operating reserve – spinning; and operating reserve – supplemental. Scheduling, system control and dispatch services and reactive supply and voltage control are only offered by the ITP. FERC proposes bid-based markets for regulation and both operating reserves to be operated by the ITP.
• The ITP would take bids to provide needed ancillary services for the next day and the ITP will consider these bids along with the day-ahead bids for energy and transmission service. The ITP can maximize economic value of the accepted bids. The price for regulation and operating reserves services would be the marginal cost of each service (the highest accepted total bid cost in $/Mw) and the opportunity cost of forgoing sales in other markets. If a generator bids is eligible to bid into more than one market operated by the ITP, the opportunity cost paid would be the forgone profit from the most profitable other market. Transmission customers would be assessed a pro rata share of the total ancillary service requirements for each of the 3 ancillary services in each hour, based on their real-time, load share ratio. Customers can notify the ITP that they want to self-provide ancillary services by scheduling them in the day-ahead market and identifying the resources that will be used.
• If the ITP's forecasted load is greater than what was scheduled in the day-ahead market, the ITP may procure replacement reserves from generators. Bids for replacement reserves will be made in the day-ahead market and the ITP will select generators in a manner to minimize costs of availability, start-up and no load costs. These generators will be paid the applicable real-time energy price for energy they produce. An uplift charge may also be paid to them if the revenues received from real-time are less than its bids for availability, start-up, no-load and energy and these costs will be allocated to the customers that benefited from them (those who did not schedule in the day-ahead market).
• Real-time energy markets will be operated by the ITP who will accept bids to buy and sell energy in each hour, and bids will be submitted on a standardized form. Bids will indicate an increase or decrease from the day-ahead schedule.
• The ITP will determine energy prices in the real-time market for each node for 5-minute increments and the price will reflect the marginal cost of producing energy and delivering it to that node in that period. FER presents and seeks comments on the two options to determine real-time prices. They are (i) to set prices using near real-time estimates (ex ante) or (ii) base the price on the actual marginal resource clearing the market in real time (ex post). FERC also seeks comment on whether market participants should be charged for uninstructed deviations in real time from their schedules.
• The ITP will no longer be able to set aside Capacity Benefit Margin for generation reliability. The ITP will be able to set aside transfer capability to ensure transmission reliability (Transmission Reliability Margi).
• Transmission capabilities will be calculated on a regional basis and all non-RTO transmission providers must contract with an independent entity to perform transmission capability calculations regionally.
• The regional planning process for transmission will identify beneficial transmission needed for reliability and cost to support regional markets and reduce the effects of generation concentration. The process will allow the market to respond to those needs. The state role in siting will be maintained, while promoting regional solutions. WECC will be a region. The first regional transmission plan should be completed within 12 months after the effective date of the final rule. The ITP will be able to issue RFPs for needed resources and parties may respond with grid expansion, generation or demand response proposals. If no acceptable bids are received, the ITP can require the transmission owners to upgrade or expand the system. The ITP would also act as a clearinghouse for proposed projects.
• The FERC proposes to use the "7 factor" test developed in Order 888 to determine which facilities are "transmission" facilities and should be under the ITP's control.
• The NOPR creates a preference for auctioning Congestion Revenue Rights, but seeks comments on whether and how allocation/direct assignment of those rights could be done.
• The major structural defect in the electric market's demand side is the lack of price-responsive demand. On the supply side, it is "load pockets" or local market power. Three mitigation measures are proposed. First is to identify certain conditions in which certain generators are in concentrated markets created by transmission congestion or reliability needs, and to cap their bids when they have localized market power. The second component of mitigation is a safety-net bid cap, setting an outer bound on suppliers' ability to exercise economic withholding. The third component is to expand resource alternatives which diminish suppliers' ability to profit from physical or economic withholding.
• A fourth market power mitigation would apply if unanticipated and sustained market conditions give market power to an entity, in a normally competitive environment. Triggers that put this mechanism into effect will have to be developed and it would be part of the ITP's tariff. Certain sellers would be exempt from mitigation, because of their size or other considerations.
• An autonomous market monitoring unit will be set up within the ITP to report directly to the FERC and the ITP board, both on a regular basis and when it observes attempts at market manipulation. It will focus primarily on detecting economic and physical withholding, but will also identify factors that contribute to economic inefficiencies. It will report on the market structure, generator conduct and the overall efficient of the sport market, the CRR market and the balance between supply and demand. It will perform a structural analysis of the region to include market concentration, conditions for entry, demand response and transmission constraints and load pockets. The ITP will include behavioral rules in the tariff with penalties for violations clearly spelled out.
• FERC proposes a resource adequacy requirement which mandates the ITP to forecast future demand for its area, facilitate determination of an adequate level of future regional resources by a Regional State Advisory Committee, and assign each LSE in its area a share of the needed future resources based on the ratio of its load to the regional load. The LSEs must meet this from self-supply, contracts to purchase, biddable demand or other demand response programs. The ITP will check to ensure that resources are not double-counted. LSEs that did not meet their obligations may be curtailed first when curtailment is necessary. A 12% reserve margin is proposed as the minimum regional margin. The planning horizon will be determined for each region, but should be long enough to bring on new resources.
• Two enforcement mechanisms are proposed for resource adequacy. A tariff penalty will be imposed on an LSE that threatens reliable transmission operations by taking energy from the spot market during a shortage in a year in which it fails to meet its resource adequacy requirement. During a shortage, the ITP must add a per-megawatt-hour penalty price to the price of energy taken from the spot market by such an LSE. The Commission will also require that spot market electric service by an LSE must be curtailed first when the shortage is severe enough to require curtailment.