| Promoting Wholesale Competition Through Open Access Services by Public Utilities
Recovery of Stranded Costs by Public Utilities and Transmitting Utilities | Docket No. RM95-8-000 Docket No. RM94-7-001 |
In the NOPR, the Commission stated that several ancillary services are needed to provide basic transmission service to a customer. These services range from actions taken to effect the transaction (such as scheduling and dispatching services) to services that are necessary to maintain the integrity of the transmission system during a transaction (such as load following and reactive power support). Other ancillary services are needed to correct for the effects associated with undertaking a transaction (such as energy imbalance service).
We proposed six ancillary services to be offered in an open access transmission tariff, which we called
We requested comments on all aspects of ancillary services, including whether the identified ancillary services are appropriately defined, whether other services should be included, and how these services should be supplied.
Commenters identified a number of other services that may be provided as part of interconnected operations. After considering the comments, we conclude that the following six ancillary services must be included in an open access transmission tariff:
A description of these services and our reasons for designating them as ancillary services are included in section 1 below. We also discuss in that section our rationale for excluding other services from the list of ancillary services that must be included in an open access transmission tariff. In section 2 below, we discuss which of the six ancillary services the transmission provider must provide or offer to provide to transmission customers, and which the transmission customer must purchase from the transmission provider. These requirements are summarized as follows:
Our requirement that these six ancillary services be included in an open access transmission tariff does not preclude the transmission provider from offering voluntarily to provide other interconnected operations services to the transmission customer along with the supply of basic transmission service and ancillary services. 349/
Commenters generally agree that some ancillary services are needed for transmission of power. Some commenters, however, argue for a different name or description for the ancillary services we proposed in the NOPR. Others argue for a more extensive list of services.
EEI believes that the term "ancillary" is a confusing description because the services are integral to providing transmission service. NERC, PSE&G, and others claim that ancillary services are not, as the term "ancillary" implies, subordinate or auxiliary to the transmission of power; rather such services are conjunctive and required to allow reliable operation of an electric system. BG&E and others contend that ancillary services should be defined as services for control area operation, 350/ and not as services provided by an individual, noncontrol area utility. NERC proposes, and many IOU commenters support, an alternative name for these services, "Interconnected Operations Services." NERC contends that the alternative name better reflects the fact that the services are needed in the broader context of allowing control areas, transmission customers, and other operating entities to operate reliably and equitably.
Some commenters propose a greater number of ancillary services. They argue that the services we proposed can be broken down into more discrete functions. A number of commenters provide rather lengthy lists of possible ancillary services to supplement those identified in the NOPR. 351/
NERC identifies twelve services, which it groups into three broad categories: interchange scheduling services, generation services, and transmission services. NERC's proposed interconnected operations services are:
(a) interchange scheduling services:
(1) system control and dispatch services; and
(2) accounting;
(b) generation services:
(1) regulation service;
(2) energy imbalance service;
(3) frequency response service;
(4) backup supply service;
(5) operating reserve service: spinning reserve and supplemental reserve services;
(6) real power loss service;
(7) reactive supply (from generation resources) and voltage control service; and
(8) restoration service; and
(c) transmission services:
(1) facilities use; and
NERC also identifies dynamic scheduling as a unique type of dispatch service that control areas must have responsibility over to ensure reliability.
Houston L&P proposes a substitute list of twenty services. NYPP proposes a substitute list of thirty-eight "unbundled components for transmission service," which include twelve generation-related services and twenty-six operations-related services. Oak Ridge recommends that the Commission consider using seven ancillary services, which closely conform to the six services described in the NOPR. 352/ Although Oak Ridge identifies several additional ancillary services, it recommends that these services not be included in the list of services to be required because they cannot be measured or because the cost of metering and billing outweighs the cost of these services.
We will adopt NERC's recommendations for definitions and descriptions with modifications. Starting with NERC's Interconnected Operations Services, we identify some of these as ancillary services that must be offered with basic transmission service under an open access transmission tariff. 353/ The definitions developed by NERC for the individual services reflect the current position of a broad spectrum of experts on the subject of interconnected operations. Adoption of NERC's terminology will provide a more universally accepted set of definitions of services. We will retain the term "ancillary services," which will refer to those interconnected operations services that we will require transmission providers to include in an open access transmission tariff.
The interconnected operations services identified by NERC incorporate all of the ancillary services proposed in the NOPR. We believe, however, that several of the individual services identified by NERC do not warrant classification as unbundled ancillary services due to the small cost involved (e.g., accounting). NERC also has identified services that, while capable of being provided in the context of integrated operations, are more appropriately provided for in a separate service agreement or other contractual arrangement (e.g., dynamic scheduling, loss compensation service). NERC and others have attempted to identify all interconnected operation services that could be provided by a control area. The thoroughness of the comments received on this issue has been invaluable to the Commission's deliberations.
We will require that an open access transmission tariff include the six ancillary services that we have identified as necessary for the transmission provider to offer to transmission customers. These are needed to accomplish transmission service while maintaining reliability within and among control areas affected by the transmission service. Other interconnected operations services, such as loss compensation service, may be provided by the transmission provider or third parties to facilitate a particular transaction or operating arrangement. We will not require other interconnected operations services as part of an open access transmission tariff. If a transmission provider supplies such services voluntarily, they may be added to a customer's service agreement with the transmission provider.
As mentioned, we will adopt NERC's definitions with modifications, and we name and describe the six ancillary services below. After each service name, we list in parenthesis the service name in the NOPR that most closely corresponds to the service defined. In the discussion, we explain whether and how we modified NERC's term.
NERC proposes a System Control and Dispatch Service, which provides for (i) interchange schedule confirmation and implementation with other control areas, including intermediary control areas that are providing transmission service, and (ii) actions to ensure operational security during the interchange transaction. A transmission customer may schedule interchange with another control area operator or with another entity inside another control area; however, the control area operators are responsible for confirming and implementing the interchange into or out of their respective areas on behalf of the transmission customer.
NERC also proposes a separate Accounting Service, which provides for energy accounting and billing services associated with interchange. Accounting Service would be provided by the operator of the control area in which the transmission service takes place.
We adopt "Scheduling, System Control and Dispatch" as the name for an ancillary service. It substitutes for the NOPR's Scheduling and Dispatching Service.
The name is NERC's recommendation with two modifications. First, we include the term "scheduling" in the name of this service because a control area operator/transmission provider must take on the function of scheduling on behalf of customers. Second, we will not require Accounting as a separate ancillary service. The purpose of separating accounting as a stand-alone service would be to allow customers to take it separately from scheduling and system control. However, we believe that accounting for scheduling, system control and dispatch is not separable from these other functions and that accounting costs are likely to be small. Therefore, accounting does not warrant separate service status. The cost of accounting for these services should be included in the cost of Scheduling, System Control and Dispatch Service.
(2) Reactive Supply and Voltage Control from Generation Sources
Service
(formerly Reactive Power/Voltage Control Service)
A number of commenters explain that reactive power and voltage control service is integrally related to the reliable operation of the transmission system. These commenters also note that reactive power and voltage support must be supplied at the location where it is needed. 354/ It cannot be provided by a distant supplier. 355/
NERC indicates that reactive supply is necessary to maintain the proper transmission line voltage for the transaction. NERC states that reactive supply is provided from both generation resources and transmission facilities (e.g., capacitors), and lists its provision as two services, distinguished by the facilities that supply them. 356/ NERC further distinguishes reactive supply service based on the source of the need for the service: (1) reactive supply needed to support the voltage of the transmission system and (2) reactive supply needed to correct for the reactive portion of the customer's load at the delivery point.
We adopt "Reactive Supply and Voltage Control from Generation Sources" as the name for an ancillary service. It substitutes for the NOPR's Reactive Power/Voltage Control Service.
We accept NERC's identification of two ways of supplying reactive power and controlling voltage. One is to install facilities, usually capacitors, as part of the transmission system. We will consider the cost of these facilities as part of the cost of basic transmission service. Providing reactive power and voltage control in this way is not a separate ancillary service.
The second is to use generating facilities to supply reactive power and voltage control. This use is the service named here, which must be unbundled from basic transmission service.
We note, however, that customers have the ability to reduce (but not eliminate completely) the reactive supply and voltage control needs and costs that their transactions impose on the transmission provider's system. For example, customers who control generating units equipped with automatic voltage control equipment can use those units to respond to local voltage requirements and thereby reduce a portion of the reactive power requirements associated with their transaction. 357/
In addition, transmission customers that serve loads can minimize the reactive power demands that they impose on the transmission system by maintaining a high power factor at their delivery points. A poor power factor at a customer's delivery point creates a need for either transmission reactive facilities (i.e., capacitors) or local generator-supplied voltage support. 358/
However, these transmission customer actions do not eliminate entirely the need for generator-supplied reactive power. The transmission provider must provide at least some reactive power from generation sources. For this reason, and because a transmission customer has the ability to affect the amount of reactive supply required, we will require that reactive supply and voltage control service be offered as a discrete service, and to the extent feasible, charged for on the basis of the amount required. 359/
(3) Regulation and Frequency Response Service
(in the NOPR: Load Following Service)
Someone must supply extra generating capacity, called regulating margin, to follow the moment-to-moment variations in the load located in a control area. Following load variations is necessary to maintain scheduled interconnection frequency at sixty cycles per second (60 Hz).
NERC and others support the need for someone to provide load following service to have generation follow a transmission customer's load changes; someone must supply power to meet any difference between a customer's actual and scheduled generation. Usually, the control area operator provides this service, but it is possible for a customer to arrange for someone else to follow its variations in load.
Many commenters indicate that the industry commonly refers to this service as "Regulation Service." 360/
Also, NERC proposes that Frequency Response Service be identified as a related but distinct service. NERC indicates that all control areas are expected to have generation and control equipment to respond automatically to frequency deviations in their networks.
We adopt "Regulation and Frequency Response" as the name of an ancillary service. It substitutes for the NOPR's Load Following Service. This name conforms to the terminology recommended by NERC.
We conclude that Regulation Service and Frequency Response Service are the same services that make up the Load Following Service referenced in the NOPR. While the services provided by Regulation Service and Frequency Response Service are different, they are complementary services that are made available using the same equipment. For this reason, we believe that Frequency Response Service and Regulation Service should not be offered separately, but should be offered as part of one service.
(4) Energy Imbalance Service
(the same in the NOPR)
Many commenters explain that Energy Imbalance Service, as proposed in the NOPR, is necessary when transmission service is provided in a control area that contains the load being served. 361/ Energy Imbalance Service supplies any hourly mismatch between a transmission customer's energy supply and the load being serving in the control area. That is, this service makes up for any net mismatch over an hour between the scheduled delivery of energy and the actual load that the energy serves in the control area. In contrast, Regulation and Frequency Response Service corrects for instantaneous variations between the customer's resources and load, even if over an hour these variations even out and require no net energy to be supplied.
We will adopt "Energy Imbalance" as the name for an ancillary service. This is the same name proposed in the NOPR. NERC's description is the same as the service proposed in the NOPR.
(5) Operating Reserve - Spinning Reserve Service and
(6) Operating Reserve - Supplemental Reserve Service
(in the NOPR these two were formerly System Protection Service)
Many commenters express confusion regarding the NOPR term "system protection." They indicate that the term "system protection," is described in the NOPR as furnishing operating reserve, but has another meaning in the industry. 362/
Operating reserve is extra generation available to serve load in case there is an unplanned event such as loss of generation. Generation held for operating reserve should be located near the load, typically in the same control area. Operating reserve amounts are set by the region, subregion, or a reserve sharing group in which the transmission customer's load is electrically located.
NERC and other commenters recommend the commonly-used name, "operating reserve," for this service. NERC also indicates that there are two types of operating reserve: spinning reserve and supplemental reserve.
Spinning reserve is provided by generating units that are on-line and loaded at less than maximum output. They are available to serve load immediately in an unexpected contingency, such as an unplanned outage of a generating unit.
Supplemental reserve is also generating capacity that can be used to respond to contingency situations. Supplemental reserve, however, is not available instantaneously, but rather within a short period (usually ten minutes). Supplemental operating reserve is provided by generating units that are on-line but unloaded, by quick-start generation, and by customer-interrupted load, i.e., curtailing load by negotiated agreement with a customer to correct an imbalance between generation and load rather than increasing generation output.
We adopt Operating Reserve - Spinning Reserve Service and Operating Reserve - Supplemental Reserve Service as the names of two related, but distinct, ancillary services. They substitute for a single ancillary service in the NOPR, System Protection Service. The names conform to the terminology recommended by NERC. We distinguish them because these services may be subject to different reliability requirements; the resources that supply each service may not be the same; and the two services may be provided by different suppliers.
Commenters discussed whether two other services that were discussed in the NOPR should be designated as ancillary services. 363/ Although we do not designate these as ancillary services for purposes of this Rule, we discuss the names and descriptions here so that we can discuss our policy regarding these services.
(1) Real Power Loss Service
(in the NOPR: Loss Compensation Service)
In the NOPR, we proposed that Loss Compensation be an ancillary service.
NERC recommends the term, "Real Power Loss," to refer to energy consumed in transmission, much of it by resistance heating of the lines and transformers. Many parties, including NERC, comment that there are a number of ways to compensate the transmission provider for the losses that occur in providing transmission service. They indicate that real power loss service can be obtained from a variety of sources, such as the power supplier, the customer, a third-party, the transmission provider, or another control area. Also, the loss is commonly accounted for by a transmission customer receiving less energy at the point of delivery than it provides to the transmission provider at the point of receipt. The difference between delivered and received energy can be set equal to the energy lost in transmission.
We adopt the term "Real Power Loss" as the name of this interconnected operations service. It substitutes for the Loss Compensation service described in the NOPR. This name conforms to the terminology recommended by NERC. Although proposed as an ancillary service in the NOPR, we will not require that Real Power Loss be included as an ancillary service in an open access transmission tariff. It is not necessary to require the transmission provider to supply energy losses to the transmission to ensure comparable transmission access. Real Power Loss is more appropriately an interconnected operations service that transmission providers may offer voluntarily to provide to transmission customers.
It is not necessary for the transmission provider to supply Real Power Loss to effect a transmission service transaction. The transmission provider is not uniquely situated to provide Real Power Loss service to its customers, nor does it have a comparative advantage over anyone in providing such a service. Indeed, to require the transmission provider to provide this service would effectively obligate the transmission provider to engage in a sale of power when such a sale is not needed to effect the transmission service transaction.
As noted in the comments, customers have several options to cover losses that occur when electricity moves across transmission facilities. 364/ The availability of open access permits the customer to obtain energy losses from many regional suppliers.
Although we will not require the transmission provider to supply Real Power Loss to the transmission customer nor require the customer to purchase it from the transmission provider, the customer must make provision for Real Power Loss. It cannot take basic transmission service without such a provision. A customer seeking transmission service must bring to the transaction sufficient energy and capacity to replace the losses associated with its intended transaction. 365/ Consequently, we will require that the transmission customer's service agreement with the transmission provider identify the party responsible for supplying real power loss. In addition, we will require that the transmission provider indicate, either in its tariff or on its OASIS, what the energy and capacity loss factors would be for any transmission service it may provide so that potential customers will know the amount of losses to replace.
(2) Dynamic Scheduling (the same in the NOPR)
In the NOPR's discussion of Scheduling and Dispatch Service, we pointed out that dynamic scheduling is possible in some regions. We asked for comments on whether we should require dynamic scheduling as an ancillary service, given the complexity of the service.
Most commenters would not have us require Dynamic Scheduling as an ancillary service. 366/ Dynamic scheduling provides the metering, telemetering, computer software, hardware, communications, engineering, and administration required to allow remote generators to follow closely the moment-to-moment variations of a local load. In effect, dynamic scheduling electronically moves load out of the control area in which it is physically located and into another control area.
We adopt the name Dynamic Scheduling Service, but we will not designate it as an ancillary service that must be included in an open access transmission tariff.
In the NOPR, we noted that Dynamic Scheduling could be used in a transmission transaction if it is technically feasible to do so without adversely affecting reliability. We did not propose in the NOPR that Dynamic Scheduling be named an ancillary service. Although Dynamic Scheduling is closely related to Scheduling, System Control and Dispatch Service, it is a special service that is used only infrequently in the industry. It uses advanced technology and requires a great level of coordination. Each Dynamic Scheduling application has unique costs for special telemetry and control equipment, making it difficult to post a standard price for the service.
Consequently, we will not require that the transmission provider offer Dynamic Scheduling Service to a transmission customer, although it may do so voluntarily. If the customer wants to purchase this service from a third party, the transmission provider should make a good faith effort to accommodate the necessary arrangements between the customer and the third party for metering and communication facilities.
Some commenters identified several other services that were not discussed in the NOPR, which they recommend we require to be provided as ancillary services. 367/ Examples are emergency power, supplemental power, and inadvertent power.
We believe that these other services generally refer to either (1) generation services that are not related to providing transmission or (2) a subpart of a service discussed above, the cost of which is not easily separable from the other service. Consequently, we will not name any of these services as an ancillary service that a transmission provider will be required to offer separately under an open access transmission tariff. However, generation-related services may be offered voluntarily to the transmission customer.
We discuss below two of these proposed generation-related ancillary services, which NERC included among its proposed interconnected operations services.
NERC explains that Backup Supply is electric generating capacity and energy that is provided to the transmission customer as needed (1) to replace the loss of its generation sources and (2) to cover that portion of the customer's load that exceeds its generation supply for more than a short time. NERC notes that Backup Supply Service is a long-term service, which distinguishes it from Operating Reserve Service and Energy Imbalance Service. Backup Supply service replaces temporary use of operating reserves; it serves load after operating reserves are returned to standby mode to maintain operating reserves at required levels. Backup Supply may last for hours, weeks, or longer. NERC indicates that a transmission customer could reduce its need for backup supply service by using interruptible load control or active demand-side management control, or both.
We accept the term "Backup Supply" as the name for this interconnected operations service, but we will not require this service as an ancillary service under an open access transmission tariff. Backup Supply Service is not required for comparable open access transmission service. Backup Supply Service is an alternative source of generation that a customer can use in the event its primary generation source becomes unavailable for more than a few minutes. Although we believe that the two short-term operating reserve services (spinning and supplemental) are necessary to support transmission, we conclude that long-term service is not necessary. Backup Supply is a generation service that may reasonably be viewed as the responsibility of the transmission customer, who may contract for backup service or curtail load.
We will impose no obligation on the transmission provider to provide power to the customer for a time longer than specified in the tariff for the customer's own backup power supply to be made available. The transmission provider is obligated to protect against emergencies for a short time; it has no obligation to furnish replacement power on a long-term basis if the customer loses its source of supply. The transmission provider has no obligation to provide power for the weeks necessary for unit maintenance, for example.
The transmission provider is not uniquely situated to provide Backup Supply Service to its transmission customers, nor does it have a comparative advantage over others in providing such service. Moreover, as Backup Supply Service may require substantial amounts of generation capability, it is inappropriate to require the transmission provider to assume significant generation responsibilities as we functionally unbundle transmission from generation. Although the transmission provider will not be required to offer this service to transmission customers, it may offer voluntarily to provide Backup Supply Service to its transmission customers. Any arrangements for the supply of such service by the transmission provider should be specified in the customer's service agreement.
NERC states that Restoration Service provides facilities and procedures to enable (1) a transmission provider to restore its system and (2) a transmission customer to start its generating units or restore its loads if local power is unavailable. Other commenters refer to Restoration Service as Blackstart Service, which may be provided by the operator of the host control area, another control area operator, or another generation supplier. 368/
According to NERC, close coordination with the host control area operator is absolutely necessary during system restoration operations. Under current industry practice, each control area operator is responsible for implementing a restoration plan in coordination with non-control area utilities as well other power producers. Many large generating units require startup power to restart after being out of service. Startup power may be provided, for example, by self-contained diesel engine generator sets located at a generating plant. If electric power is not available from the grid, some and perhaps many plants must obtain the necessary power from their auxiliary generators to restart plants and return the grid voltage to the proper level. Other generators without blackstart capability may rely on power from the grid to restart, once the grid is energized by others. NERC notes, however, that it may be inappropriate to rely completely on power from the grid for restart power because power from the grid may be unavailable or insufficient. Consequently, at least some power plants must have internal auxiliary power sources.
We accept the term "Restoration" as the name for this interconnected operations service. We will not require the transmission provider to offer Restoration Service as a separate ancillary service in an open access transmission tariff.
Comments on Restoration Service appear to describe two services, blackstart service and planning for system restoration. Presumably, each utility and power producer will do its part through voluntary coordination and self-interest to ensure a reliable and adequate source of startup power for its generating units. We will not require a transmission provider to provide blackstart capability to transmission customers. Generators without blackstart capability can instead purchase blackstart power from any power supplier connected to the grid at an appropriate power price, if such service is available after a contingency is corrected. The obligation to plan for restoration capability is a system control area function that rests with the transmission provider and the operator of the control area in which the transmission provider is located. The transmission provider (or its associated control area operator) generally makes arrangements with enough generators to provide the system with this capability at strategic locations on the transmission system. Thus, restoration planning is intrinsic to the transmission provider's basic transmission service and included in its cost.
2. Obligations of Transmission Providers and Transmission Customers with Respect to Ancillary Services
In the NOPR, the Commission proposed that public utilities required to file open access transmission tariffs also be required to provide unbundled ancillary services to transmission customers. Although the NOPR included a list of ancillary services to be offered by transmission providers, the NOPR did not indicate whether a customer must take basic transmission service from the transmission provider to be eligible to require the transmission provider to supply ancillary services. Comments on these issues are summarized below. 369/
Several commenters 370/ distinguish generation-related ancillary services from others. Generation-related services are those that require the provider to have extra generating capacity or to provide electric energy. The remaining ancillary services are called transmission-related services or control area services. Transmission-related services would involve, for example, voltage support from transmission facilities. An example of a control area service is system control and dispatch. Commenters do not agree on how each service should be classified.
Many commenters state that only control area operators should be allowed to offer certain ancillary services, such as scheduling, system control and dispatch. 371/ They believe that otherwise reliability might suffer.
Minnesota P&L states that certain ancillary services (e.g. reactive power from generators, load following, frequency control) should be provided exclusively by the operator of the control area where the load resides. 372/ Minnesota P&L indicates that obtaining these services externally could jeopardize reliability. Several commenters claim that a control area operator must provide the scheduling, system control and dispatch service and reactive power supply service (except in cases where the customer's load is very close to the generating source). 373/ Numerous commenters indicate that load following (now called Regulation and Frequency Response Service) generally is provided only by a control area operator. 374/
EEI and other commenters state that energy imbalance service must be provided by either the control area operator or some other entity that is in the control area where the customer's load is located and has real-time response capability. 375/ NYSEG points out that transmission providers generally are also control area operators and thus automatically provide energy imbalance service to maintain interchange flows and control area reliability. For this reason, NYSEG believes it is important that this service remain a responsibility of the transmission provider.
SC Public Service Authority contends that ancillary services can be provided only by an entity large enough to operate at a NERC regional scale. It states that ancillary services protocols must be established regionally to support regional transmission services.
Other commenters disagree. They argue that all the generation-related ancillary services identified in the NOPR can be obtained from sources other than the transmission provider. 376/ American Wind believes the ability of a transmission customer to self-supply ancillary services or purchase them from a third party will help to curb inflated prices for such services. Southwest TDU Group also claims that permitting entities outside the transmission provider's control area to provide ancillary services will enhance competition and reduce the need for Commission oversight of charges for ancillary services.
A majority of commenters support the view that the transmission-providing public utility should provide ancillary services. Many commenters do not discuss the services individually but present their views generally on the provision of ancillary services. Missouri-Kansas Industrials and CCEM support a requirement that utilities make ancillary services available through a tariff. They argue that, from a customer's point-of-view, it is extremely critical that a transmission provider be required to furnish these services under a regulated, nondiscriminatory, cost-based tariff format. NIEP argues that, until a fully competitive market for ancillary services develops, transmitting utilities should be obligated to provide or arrange for any and all of the NOPR ancillary services, to the extent that the transmission customer desires such services. Direct Service Industries emphasizes that a transmission provider should be required to provide any ancillary service that it is capable of supplying. Direct Service Industries and Utilities For Improved Transition claim that open access tariffs should state clearly that the transmission provider must secure ancillary services for a transmission customer if the transmission provider is not able to provide these services itself. Large Public Power Council contends that, during the transition to a competitive market for generation-related ancillary services, transmission providers should be required to provide all ancillary services related to generation that existing customers now take on a bundled basis. OH Com notes that transmission owners, by virtue of their position as transmission owners, are necessarily the providers of last resort for certain ancillary services. OH Com therefore believes that only transmission providers should provide ancillary services.
Several non-IOU, transmission-owning commenters, however, urge that the Commission not require transmission providers to provide ancillary services that they cannot physically supply, i.e., if they lack sufficient generation, lack control area facilities, or have slow-responding generating units. 377/ NRECA and TDU Systems also state that many cooperatives and transmission dependent systems presently obtain ancillary services from control area utilities under specific contract terms. Consequently, if their member systems are asked to provide transmission service, they may not be able to take on the obligation to secure ancillary services under their existing contracts for transmission customers. Soyland and Pacific Northwest Coop argue that a transmission provider should not be required to supply services that it does not provide to its native load.
Most IOU commenters and others oppose a requirement that the transmission provider be obligated to provide generation-related ancillary services. They offer the following reasons: (1) the need for such services differs from one transaction to the next; (2) a transmission provider is neither uniquely qualified to provide these services, nor is it essential that such provider be the one providing these services in order to effect a transaction; (3) until it is demonstrated that these services cannot be obtained from a source other than the transmission provider, it is inappropriate to require transmission providers to supply such services; and (4) a transmission provider should have no residual obligation as a provider of last resort to plan its system to have generating resources available for the supply of ancillary services. 378/ IL Com also contends that utilities should not be required to provide generation-related ancillary services under general transmission service tariffs if such services can be obtained from the bulk power market.
Other IOU commenters argue that there is a fundamental inconsistency between an obligation to provide or obtain ancillary services for customers and the NOPR's unbundling requirement. For example, BG&E claims that it is inconsistent to require the traditional vertically integrated utility to functionally unbundle and also to remain responsible for providing at cost-based rates what should be competitively-priced generation services. Florida P&L and other IOU commenters argue that providing generation-related ancillary services effectively imposes the load-serving obligation of the transmission customer on the transmission provider.
However, some IOU commenters contend that the transmission provider or its agent should be required to provide certain ancillary services. 379/ NIPSCO and PacifiCorp believe that load following (now called Regulation and Frequency Response Service) should be provided only by the transmitting utility, especially if the customer's load and resources are located in the control area operated by the transmitting utility. EEI contends that a third-party generator should have the opportunity to provide regulation service if it resides in the transmission provider's control area and coordinates its actions with the control area operator.
IN Com and NY Com recommend that the Commission provide flexibility in assessing responsibility for the supply of ancillary services. MN DPS recommends that an individual transmission provider should not be required to file an individual tariff for ancillary services if it is a member of an RTG whose tariffs adequately cover the same services.
EEI contends that a control area utility should not be required to provide ancillary services to a third party outside its control area. EEI also argues that, if the transmission provider is not a control area, it should not be required to procure ancillary services from a control area on behalf of a third party seeking service over its system. Rather, the third party should be responsible for procuring the ancillary services it needs. Other IOU commenters argue that the responsibility to acquire ancillary services belongs to the transmission customer, not the transmission provider. 380/
Many IOU commenters express concern that ancillary services be offered and taken on a symmetrical basis, i.e., if transmission providers are uniquely situated to provide the service, customers should likewise be required to take and pay for the service from such transmission providers. 381/ BG&E claims that it is patently unfair to give third-party users the option not to purchase ancillary services that the transmission provider must offer. BG&E argues that, if transmission providers have an obligation to provide ancillary services, equity dictates that transmission customers have a corresponding obligation to take those services or compensate transmission providers for the costs associated with the unused capabilities. United Illuminating argues that the requirement to provide service without a corresponding obligation to purchase service unfairly burdens the transmission provider and skews competition in favor of transmission customers.
Other non-IOU commenters oppose a symmetric obligation to provide and purchase particular ancillary services. 382/ Ontario Hydro and others claim that the customer should decide on a case-by-case basis which ancillary services it needs to purchase.
BPA and BG&E assert that transmission providers should be able to require that the party receiving the power, which may not be the transmission customer, be responsible for acquiring ancillary services. This would allow the transmission provider to establish the appropriate contractual arrangements with the party that is actually receiving the energy and avoid shifting responsibility to a party that is merely arranging the transmission service.
A number of IOU commenters express concern that customers may "lean" on a transmission provider's system for ancillary services. That is, they worry that the transmission customer may not purchase an ancillary service but nevertheless rely on the transmission provider to provide it. Commenters propose various remedies to address this concern. NIEP, Dayton P&L and others argue that the Commission should require that, as a prerequisite to basic transmission service, the transmission customer has either arranged to obtain ancillary services from the transmission provider or has demonstrated it has an arrangement with an alternative supplier that is reliable and sufficient to satisfy the ancillary service needs associated with the transmission service transaction. NYPP believes that, if the customer's method of providing ancillary services does not meet the standards of the transmission provider, the transmission provider should be able to require that the transmission customer find another ancillary service supplier or purchase the service directly from the transmission provider at its tariff rates. 383/ EEI proposes that penalties be permitted as a backstop if the market cannot resolve the "leaning" problem. VEPCO suggests that utilities should have the option to require customers to maintain backup supply reserves.
The NOPR proposed that six ancillary services be included in an open access transmission tariff. Some commenters interpret the NOPR to require that transmission providers make a "universal" offer of unbundled ancillary services, i.e., an offer to any transmission customer regardless of location and whether the transmission customer would also be taking basic transmission service from the supplier of ancillary services. 384/ Such interpretation is incorrect; it goes beyond what is required for comparability. These services are required to be provided only to customers taking basic transmission service. However, transmission providers may offer these services on a voluntary basis to other customers if technology permits.
Transmission through or out of a control area requires fewer ancillary services from the operator of the control area than transmission within or into a control area to serve loads in the control area. If the requested transmission service transaction involves more than one control area, i.e., the receipt point and delivery point of transmission service are located in different control areas, certain ancillary services will be needed only in the control area where the transmission customer's load is located.
We will distinguish two groups or categories of ancillary services: (1) services that we will require the transmission provider to provide to all its basic transmission customers, and (2) services that we will require the transmission provider to offer to provide only to transmission customers serving load in the provider's control area. The first group is comprised of (i) Scheduling, System Control and Dispatch and (ii) Reactive Supply and Voltage Control from Generation Services. The second group is comprised of (i) Regulation and Frequency Response, (ii) Energy Imbalance, (iii) Operating Reserve - Spinning, and (iv) Operating Reserve - Supplemental.
With respect to the first group of ancillary services, we conclude that the transmission provider that operates a control area is uniquely positioned to provide these services. Thus, as stated above, we will require the transmission provider that operates a control area to provide these ancillary services. We will also require that the transmission customer purchase these services from the transmission provider, as explained in the next section.
With respect to the second group of ancillary services, we conclude that the transmission provider is not always uniquely positioned to provide these services, although in many cases it may be the only practical source. Thus, we will require the transmission provider to offer to provide the ancillary services in the second group to transmission customers serving load in the transmission provider's control area. We also will require the transmission customer serving load in the transmission provider's area to acquire these services, but it may do so from the transmission provider, a third party or self-supply. These ancillary services must be provided by someone if the system is to be operated reliably; the customer may not decline the transmission provider's offer of ancillary services unless it demonstrates that it has acquired the services from another source. The transmission provider may require the customer to decide which of these ancillary services it will purchase from the transmission provider when it applies for basic transmission service.
If the transmission provider is a public utility providing basic transmission service but is not a control area operator, it may be unable to provide some or all of the ancillary services we require without substantial investment. In this case, we will allow the transmission provider to fulfill its obligation to provide, or offer to provide, ancillary services by acting as the customer's agent. We will require the transmission provider to offer to act as agent for the transmission customer to secure these services from the control area operator. 385/ The customer may have the transmission provider act as agent or may secure the ancillary services directly from the control area operator. As stated above, the customer may also secure the second group of ancillary service from a third party or by self- supply.
If the transmission provider is a public utility that is not a control area operator, but its control area operator is a public utility, the control area operator must offer to provide all ancillary services to any transmission customer that takes transmission service over facilities in its control area whether or not the control area operator owns or controls the facilities used to provide the basic transmission service. 386/
We discuss the requirement to supply and purchase each ancillary service individually below.
We conclude that this service is necessary to the provision of basic transmission service within every control area. As NERC and other commenters point out, Scheduling, System Control and Dispatch Service can be provided only by the operator of the control area in which the transmission facilities used are located. 387/ This is because the service is to schedule the movement of power through, out of, within, or into the control area.
We conclude that this service is necessary to the provision of basic transmission service within every control area. Because reactive power cannot be transmitted for significant distances, the local transmission provider has to supply reactive power from generation sources. It is often uniquely situated to supply reactive power. The transmission provider or the operator of the control area in which the provider is located cannot avoid supplying it to the transmission customer, and the transmission customer cannot avoid taking at least some of this service from the transmission provider. Although a customer is required to take this ancillary service from the transmission provider or control area operator, it may reduce the charge for this service to the extent it can reduce its requirement for reactive power supply.
Regulation and Frequency Response Service is not required for transmission out of or through the transmission provider's control area. We conclude that this service must be offered only for transmission within or into the transmission provider's control area to serve load in the area. Customers may be able to satisfy the regulation service obligation by providing generation with automatic generation control capabilities to the control area in which the load resides. Dynamic scheduling may also be used to electronically "move" a remote generating unit into the appropriate control area. For customers to take advantage of these developments, a transmission provider is required to identify the regulating margin requirements for transmission customers serving loads in its control area and develop procedures by which customers can avoid or reduce such requirements.
We conclude that Energy Imbalance service must be offered for transmission within and into the transmission provider's control area to serve load in the area.
Energy imbalance represents the deviation between the scheduled and actual delivery of energy to a load in the local control area over a single hour. A transmission customer can reduce or eliminate the need for energy imbalance service in several ways. A customer can avoid taking energy imbalance service if it controls generation with load-following capabilities located in the control area. The Final Rule pro forma tariff allows unlimited changes before the hour at no additional charge to a customer's hourly schedule of energy deliveries to the control area. By changing its schedule more frequently (based on updated load information, for example), a customer can reduce or avoid energy imbalance charges. Other customer options to reduce or avoid energy imbalance charges include (i) establishing the load as a separate control area island within the transmission provider's control area with its own generation and load and (ii) removing the customer's load from the transmission provider's control area through dynamic scheduling. 388/
We conclude that Operating Reserve - Spinning and Operating Reserve - Supplemental must be offered for transmission within and into the transmission provider's control area to serve load in the control area. Reserves should be located near load in case of unplanned unavailability of generating units serving load in the control area. We will permit transmission providers to rely upon prevailing regional practices to set reserve criteria. Transmission providers are required to facilitate efforts by customers to meet Operating Reserve obligations with their own generating resources or from third-party sources if they can satisfy the regional criteria.
If a customer uses either type of operating reserve, it must expeditiously replace the reserve with backup power to reestablish required minimum reserve levels.
In the NOPR, the Commission proposed that transmission providers should be required to offer ancillary services as discrete services, unbundled from basic transmission service.
While most commenters support the approach to unbundling the ancillary services proposed in the NOPR, a number of commenters argue that, for technical and administrative reasons, certain services should be bundled with basic transmission service. For example, some commenters assert that Reactive Supply and Voltage Support service should be bundled with basic transmission service. 389/ They argue that this service is integrally related to the operation of the transmission system, that it must be provided at or near the point of need, and that its costs are difficult to isolate and account for. 390/ Other commenters argue that scheduling and dispatch service, for similar reasons, should be bundled with basic transmission service. 391/
A few commenters suggest that other services could be bundled with the basic transmission service. For example, NYSEG identifies energy imbalance service as a candidate for bundling.
EEI identifies frequency regulation and NYMEX identifies frequency control as services that could be bundled with basic transmission service.
Some commenters believe that the Commission should allow utilities to file transmission tariffs that bundle all necessary transmission and ancillary services, at least as an interim measure. 392/
On the other hand, other commenters believe that a greater level of unbundling of transmission and ancillary services is necessary to facilitate the development of competitive markets and to ensure that transmission customers are able to purchase only the services they require. 393/ Dayton P&L believes that all ancillary services should be offered as discrete services with separate prices. Texas Utilities asserts that generation-related ancillary services should be unbundled and separately priced.
Although commenters raise valid concerns, they do not provide a compelling reason to require that our six ancillary services be bundled with basic transmission service. We have, however, changed the proposal in the NOPR to clarify that reactive supply and voltage support from transmission resources is part of basic transmission service.
Unbundling ancillary services will promote competition and efficiency in their supply. Because most generation-based ancillary services potentially can be provided by many of the generators connected to the transmission system, some customers may be able to provide or procure such services more economically than the transmission provider can. Once they are unbundled, a more competitive market may emerge to supply such services.
Also, unbundling makes possible a more equitable distribution of costs. Because customers that take similar amounts of transmission service may require different amounts of some ancillary services, bundling these services with basic transmission service would result in some customers having to take and pay for more or less of an ancillary service than they use. For these reasons, the Commission concludes that the six required ancillary services should not be bundled with basic transmission service.
With respect to the specific question of whether Reactive Supply and Voltage Control from Generation Sources should be bundled with basic transmission service, we believe that this service should remain unbundled because, as explained above, transmission customers have some ability to affect how much of this service they need and a third party may be able to supply some portion of a customer's reactive power requirements.
The NOPR indicated that ancillary services must be offered separately from one another but did not indicate if the transmission provider may also offer a package of ancillary services.
Several commenters support giving customers the option either to purchase ancillary services as separate and distinct services or to purchase a package of services from the transmission provider. 394/ Others, such as Tallahassee, recommend that utilities be prohibited from bundling the purchase of one service with another so that a transmission customer cannot rely on the transmission provider for just one or a few of the ancillary services.
EEI and ELCON argue that the Commission should permit customers the option to request that transmission providers offer packages of selected ancillary services. 395/ They and other commenters express a concern that efficiencies can be lost under a policy that precludes combining ancillary services.
We conclude that a transmission provider must offer and price the individual ancillary services separately. It may not tie the purchase of one to the purchase of another.
However, we will allow a transmission provider to assemble packages of ancillary services (not bundled with basic transmission service) that can be offered at rates that are less than the total of individual charges for the services if purchased separately. It may also offer rate discounts on any ancillary service. If a rate discount is offered to the transmission owner itself or to an affiliate of the transmission owner, the same discount must be offered to non-affiliates, as well. In addition, discounts offered to non-affiliates must be on a basis that is not unduly discriminatory. All discounts must be posted on the transmission provider's OASIS.
In the NOPR, the Commission noted that ancillary services may not be suitable for reassignment and requested comments on this issue.
Commenters express divided views on the reassignment issue. Some IOU commenters believe that, subject to technical limitations, ancillary services could be reassigned. 396/ Other commenters, including many IOUs, oppose reassignment because they believe it is impractical. 397/ In particular, PacifiCorp claims that the customer-specific nature of generation-related ancillary services prevents such services from being reassigned.
TDU Systems argue that transmission customers that must pay for ancillary services they do not need should be able to resell them to someone else. 398/ Mt. Hope Hydro claims that, if a bulk power transaction and the associated transmission service can be reassigned, it is reasonable that the ancillary services used to support the transaction also should be reassigned, particularly if the same facilities and contract path are used. 399/
We conclude that transmission customers will be allowed to reassign ancillary services along with the reassignment of basic transmission service. The Commission believes that a policy of transmission capacity reassignment may not be possible unless the ancillary services used to support the transmission are also reassignable.
In the NOPR, we asked for comments on ancillary service pricing and proposed specific ancillary services prices in the Stage One implementation rates. Many commenters commented on the Stage One rates. There is no Stage One in the Final Rule.
Many commenters state that ancillary services are difficult to price. They suggest diverse pricing approaches. IN Com notes that, because utilities and regulatory commissions have no experience with pricing unbundled ancillary services, the process needs to evolve but the goal should be to encourage market pricing in competitive markets. Air Liquide believes the best pricing policy should be negotiated bilateral agreements, provided market power is mitigated.
Other commenters express concern about how pricing proposed in the NOPR would affect the development and operation of competitive ancillary services markets. Industrial Energy Applications notes that low price caps on generation-related services, such as supplying losses, imbalance energy, operating reserve and backup power, which can be provided from many sources, inhibit competitive market development. There is little incentive for other providers to invest in facilities to provide these services. Dayton P&L and others contend that the Commission should not require transmission providers to provide generation-based ancillary services at cost-based rates and then allow third parties to resell such services at market-based rates. PacifiCorp expresses concern that the NOPR's pricing proposal would be overly restrictive in the emerging competitive market for generation-related ancillary services. Many commenters argue that cost-based price caps are appropriate for ancillary services if there are no alternative suppliers or until competitive markets develop. 400/ CAMU suggests that the comparability standard is not met if market rates exceed the costs of providing ancillary services. Allegheny, Ohio Edison and Atlantic City support cost-based pricing for Reactive Power/Voltage Control. Ohio Edison recommends cost-based pricing for frequency regulation, and Atlantic City recommends it for scheduling and dispatch.
Several commenters suggest that the Commission require cost- based rates for ancillary services where no source other than the transmission provider exists and market-based rates for generation-related ancillary services if competition exists. 401/ Washington and Oregon Energy Offices recommend that, before permitting market-based rates, at least two other non- affiliated parties should be able to offer a nearly identical ancillary service and that the Commission should use the same standards for allowing market-based rates for ancillary services that it has used for wholesale power sales. Mt. Hope Hydro argues that vertically integrated utilities should be permitted to charge cost-based rates that are limited to no more than the market price for ancillary services. It also contends that companies whose generation facilities are not supported by captive retail or transmission customers should be authorized to sell at market-based prices.
The vast majority of commenters from all interest groups who address market-based pricing for ancillary services agree that market-based pricing is appropriate for ancillary services where competitive market conditions exist. However, commenters disagree over whether a competitive market for ancillary services currently exists.
In determining the extent of competition, many commenters distinguish between ancillary services that are (1) generation- related and (2) transmission-related. Commenters disagree over whether the Commission can declare generation-related ancillary services to be competitive on a generic basis. Many commenters contend that transmission-related ancillary services are not available in a competitive market; consequently, they agree that prices for such services should be cost-based.
We will consider ancillary services rate proposals on a case-by-case basis.
In response to comments, 402/ we offer here some general guidance on ancillary services pricing principles.
Some commenters suggest that there may be a need for revising the Uniform System of Accounts to track better the costs of providing discrete ancillary services. Other commenters believe that ancillary services are transmission-type services and suggested that the costs of generation-provided ancillary services be refunctionalized from power production expense to transmission expense.
Oak Ridge asserts that a primary goal of those interested in restructuring the electricity industry should be to identify clearly the different functions that are today buried within the vertically integrated utility and bundled into one price. Oak Ridge, however, indicates that achieving this ideal of identifying unbundled services at appropriate prices will be difficult because of utility accounting practices.
EEI asserts that since the current Uniform System of Accounts was designed to track costs incurred to provide bundled wholesale service, it does not track the discrete costs incurred to provide ancillary services. Therefore, according to EEI, a major update is needed to support the pricing of discrete ancillary services.
ConEd states that ancillary services are integral and essential elements of providing transmission services. It notes that, historically, due to the vertical integration of utilities, those services have been bundled with the other services provided and the costs associated with providing ancillary services have not been specifically defined. ConEd claims that to a large degree, this is due to the fact that utility accounting mechanisms were not established with the intention of identifying the costs for ancillary services.
UI asserts that if transmission customers are to be charged for certain ancillary services, it may be necessary to refunctionalize certain specific costs items from generation to transmission. UI points out that some of the reactive power to support system voltages and to provide transmission services, for example, is supplied from the variable reactive output of the generators. It states that these costs, to the extent they can be identified with the provision of transmission service, should be refunctionalized to the transmission account. However, UI states it may not be possible to develop a unit cost for specific transactions. Thus, UI states it may be more appropriate to roll these costs into the embedded transmission rate and allocate them among the various users of the transmission system.
To ensure comparable transmission access a Transmission Provider is obligated to offer or arrange to provide certain ancillary services to the Transmission Customer. Also, the Transmission Provider may offer to provide other ancillary services to the Transmission Customer. A Transmission Customer is obligated to purchase certain ancillary services from the Transmission Provider.
Generation resources provide certain ancillary services, while transmission resources provide other ancillary services. Consequently, the costs of providing certain ancillary services are recorded in the utility's power production expense accounts, while others are recorded in the utility's transmission expense accounts.
Currently, the Uniform System of Accounts requires that costs incurred in providing ancillary services be recorded as power production or transmission expense depending upon which resource the utility uses to supply the service. At this time, we are not convinced that the amounts involved or the difficulty associated with measuring the cost of ancillary services warrants a departure from our present accounting requirements. We will specify, however, that revenues a Transmission Provider receives from providing ancillary services must be recorded by type of service in Account 447, Sales for Resale, or Account 456, Other Electric Revenues, as appropriate.
Convergence Research - 5/2/96