FERC Filings
FERC RTO NOPR COMMENTS
Minimum Functions
Minimum Functions
The NOPR identifies seven minimum functions RTOs perform. EPSA offers the following comments on those functions.
A.
Administer Its Own Tariff and Employ a Transmission Pricing System That Will Promote Efficient Use and Expansion of Transmission and Generating Facilities
The NOPR includes several requirements within this function. An RTO must be the sole provider of transmission service for the facilities under its control. It must also be the sole administrator of its own Commission-approved open access transmission tariff. The RTO must also have the sole authority to receive, evaluate, approve or deny requests for transmission service, as well as to review and approve requests for new interconnections. The RTO tariff must eliminate pancaked rates. Each of these is an important requirement.
The primary objectives in creating RTOs are to facilitate the emergence of broader and deeper competitive markets through efficient regional transmission system management and by eliminating the potential for the exercise of vertical market power by traditional, integrated utilities. RTOs can offer a significant advantage to participants in the wholesale power market and in emerging competitive retail markets by allowing transmission and interconnection customers to conveniently arrange for all required transmission (and distribution) and interconnection services with ex ante prices at agreed-upon and understood terms and conditions. Aside from offering the efficiency benefits of one-stop shopping, the RTO can aid market participants by making transmission a more uniformly priced commodity. The Commission should not lose sight, however, of the value of a liquid secondary market in transmission and transmission-related products. The RTO should be charged with facilitating the trading of those products and should not be permitted to strengthen its status as a monopoly provider of transmission or related products.
On the issue of pancaking, FERC has recognized that, while transmission pricing must meet the revenue requirements of the transmission system's owners, it should also be non-discriminatory and promote economic efficiency. Thus, FERC acted to require that transmission pricing reflect comparability (namely, the transmission owner charges itself the same as others for the same service), that transmission pricing be fair and practical, that transmission pricing promote economic efficiency and that it meet the traditional revenue requirement.
In order to reflect true comparability, however, all transmission service must be reserved and provided pursuant to the same, system-wide tariff. RTO open access tariffs should be revised to incorporate this requirement. Moreover, for the reasons set forth in the Petition for Rulemaking (supra, footnote 6), FERC should eliminate the native load priority accorded by Order No. 888. As noted earlier, the establishment of an RTO is not sufficient in itself to assure comparability. It represents only one step. Requiring all transactions - including those for native load - to follow the same terms and conditions for transmission transactions is equally, if not more, critical to efficient operation of the electricity market. With all market participants using the same tariffs, the industry itself would drive towards regionalization and would achieve voluntarily the resulting benefits. A single tariff would eliminate much of the acrimony, distrust and strife accompanying current ISO formation as market sectors facing different competitive pressures attempt to retain their current advantages.
RTOs also will establish conditions that may encourage states to permit the unbundling of retail services, which EPSA supports. To that end, RTOs must provide the organizational framework within which retail and wholesale market participants will be required to procure transmission services on a comparable basis. As the NOPR points out, they can also facilitate state retail access programs "by providing greater confidence in the markets and a larger regional market with access to more potential suppliers."
EPSA also supports initiatives that will lead to a reduction in transmission costs. The appropriate measure of transmission pricing is to set rates to encourage the efficient operation and use of the system. Transmission service has been a small portion of integrated utilities' businesses, and transmission revenues played a small role in utilities' operating expenses. Thus, in 1996, transmission service constituted two percent of utilities' overall operating expense budgets. Transmission prices, nonetheless, provide important price signals that can create efficiencies in the wholesale bulk power market. Generators and marketers are sensitive to transmission rates. Pancaked rates are a de facto means of maintaining market power because they impede generators' and marketers' efforts to sell power to a wide array of buyers, potentially over significant distances.
A major goal of the new RTOs must be to further the efficient use of transmission resources and to eliminate pancaked transmission rates. Pancaking bears no relation to efficient market operation. The NOPR, echoing FERC's ISO Principle No. 3, which EPSA supports, succinctly states the goal: an RTO should provide services at non-pancaked rates pursuant to a single, unbundled grid-wide tariff.
While transmission rates are likely, in the near term, to reflect historic, zone-specific rate-setting practices in order to minimize cost shifting, over the longer term, RTOs should adopt common, system-wide rates over much larger geographical areas in order to increase the efficiency of long-distance transmission. Customers, however, should be protected from disproportionate, abrupt shifts in transmission rates. Thus, while a common transmission rate over the full territory of an RTO is the appropriate goal, existing contracts should be honored and/or phase-in periods should be of sufficient length to reduce the transition impact on customers and on the original transmission provider.
The NOPR also points out that "RTOs would facilitate establishing transmission rights and the 'tradability' of transmission rights." Clear rules establishing transmission rights can also help the market allocate transmission efficiently, send pricing signals when new investment is needed, facilitate a secondary market in transmission services, promote redispatch options, encourage the development of trading hubs to promote efficient trading, and allow market participants to hedge prices. A more robust secondary market can play an important role in achieving the Commission's goals for competitive wholesale electricity markets. A secondary market can react more quickly to transmission market needs, sending appropriate price signals to interested market participants. A secondary transmission market also gives market participants more options, allowing transmission customers, not just transmission providers, to hedge risks associated with transmission reservations. It will also provide more flexibility, as transmission customers may offer alternative transmission products to this market.
B.
Create Market Mechanisms to Manage Transmission Congestion
The NOPR requires RTOs to develop and operate market mechanisms to manage transmission congestion, noting that "[a]n RTO would be in a better position to prevent congestion or control it through application of appropriate region-wide congestion pricing to ration use of the grid if necessary." RTOs can also "more readily identify schedules that could lead to congestion, and relieve congestion through regional redispatch authority." EPSA agrees, and believes one of the most important roles for RTOs is to facilitate economically efficient regional redispatch as a means of minimizing curtailments.
While there may be general agreement on the need for regional redispatch procedures, there is little agreement over how to account for the costs of transmission congestion. Of course, the prospect of transmission congestion is not new, as the constraints on the system are hardly new. In the past, integrated utilities routinely redispatched their own generation, running their units out of economic merit order, with such "out-of-merit" costs traditionally rolled into an overall transmission service charge or allocated to native load through fuel adjustment charges. All customers would thus contribute to the payment of the congestion charge, on the theory that all transmission usage contributed to the congestion and all benefited from its elimination.
The unbundling requirements of Order No. 888, however, have separated the cost of transmission from the cost of relieving congestion. Order No. 888 established no ready mechanism to apportion the costs of redispatch. Thus, while congestion charges should now be explicitly recognized, it is still appropriate to spread many of those costs to all system users, since, just like before Order No. 888, redispatch generally benefits all users of the transmission system.
This problem is compounded because transmission rights are not well-defined today. This has led, in some instances, to transmission providers overselling their systems, which in turn has led to increased use of blunt congestion management tools, such as NERC's transmission line-loading relief ("TLR") procedures. With transmission rights more clearly defined and allocated, ATC calculations can be made more accurately and congestion management simplified. RTOs can play an important role in defining and facilitating these new transmission products. In addition, RTOs can play an important role by internalizing and thus minimizing congestion costs.
The NOPR requires that RTOs ensure the development and operation of market mechanisms to manage transmission congestion. They should be responsible for developing the economic models for redispatch or other congestion charges, known in advance, with the goal of allowing the market to ration the use of transmission based on its value. Ideally, such economic rationing schemes should be uniform across RTOs and should be implemented as an ancillary service under a regional transmission tariff.
Congestion is increasingly important as a result of the growing use of the transmission system. Between 1990 and 1996, for example, utilities' purchases of energy grew from 563,370 gigawatthours ("gWh") to 843,370 gWh, or an increase of 33 percent overall. Wholesale sales similarly grew over this period, from 444,180 gWh to 608,480 gWh, an increase of 27 percent. This growth is greater than the 5.7% growth of overall electrical demand in the United States over the same time period.
The traditional use of the transmission system focused on each utility's generation plants and its loads. Now, as marketers and merchant generators are playing an increasingly important role, and as uniform, system-wide tariffs are introduced, there will be increased use of the transmission system. In addition, there are potentially troublesome claims of increased constraints when divested generation must now obtain transmission service over the same wires historically used to move its product to market. Proper incentives for congestion management, such as discounted counterflows and market redispatch options, or investment in new facilities and technologies, would largely alleviate concerns about higher levels of congestion. EPSA
supports the unbundling of congestion charges because it makes the pricing of transmission service more transparent and more efficient. In addition, market-based pricing of redispatch costs, that is, congestion charges, is an effective means of evaluating the true cost of the congestion against the cost of resolving the congestion, that is, upgrading the system.
Fair and meaningful measures of congestion provide an efficient means of avoiding the curtailment of transactions during periods of peak demand. While locational based marginal pricing of energy is one way to measure and apportion the costs of transmission congestion, market participants have suggested other efficient ways of doing so. For example, the RTO could solicit supply-side bids designed to relieve congestion in load pockets. Such bids could include offers to forego energy purchases or implement other demand-side measures. There could also be bilateral solutions to these problems. An RTO, therefore, should be able to inform generators of how much they expect to be compensated if their unit is backed down as a result of congestion and facilitate bilateral solutions to congestion.
Another RTO role is to provide power marketers and prospective developers with information as to the charges they likely would incur as a result of scheduled transactions and/or decisions to locate a new generating facility at a particular location. Market participants need price certainty in advance of a transaction to make rational economic and risk management decisions. In addition, to further the goal of fostering wholesale competition, the Commission needs to consider whether marginal pricing of congestion, which imposes potentially huge costs on individual transactions, provides greater benefits than a system that internalizes more of these costs.
Meaningful regional redispatch and other forms of congestion relief under the aegis of an RTO are essential alternatives to present TLR protocols of individual transmission providers. EPSA welcomes FERC's recent directives requiring the non-discriminatory implementation of TLR (i.e., that TLR protocols be applied comparably to native load and transmission customers). Indeed, NERC recently proposed measures intended to implement this comparability requirement, which EPSA agreed to in principle. Nonetheless, EPSA remains concerned that applying TLR to wholesale and retail service may be insufficient to remedy all of the discriminatory effects of TLR usage. The reason is that TLR is only applied to transactions over an interface and under the pro forma tariff. Most transmission owners serving retail load do not engage in interchange transactions or use the pro forma tariff at the same level as new competitive market entrants attempting to enter historically captive markets. Thus, even if TLR is applied in a fully comparable manner, it will still disproportionately and adversely affect new competitive market entrants.
Finally, in the absence of transmission-to-transmission competition, it is much more efficient for an RTO to determine the amount of congestion and the most economical way of alleviating such congestion than it is for individual transmission owners, with each striving to maximize its own competitive or parochial interests. The era of voluntary harmonious communication among transmission providers for the benefit of all customers within a region is over. Competition forces companies to think and behave parochially. As an impartial operator of transmission, RTOs can play an important role in facilitating efficient congestion management.
C.
Develop and Implement Procedures to Address Parallel Path Flow Issues
As the NOPR notes, the historical "disconnect" between contract path assumptions and parallel path realities is becoming increasingly significant. As discussed in the NOPR and in these comments, establishing RTOs of sufficient size will internalize most parallel path or "loop" flows to one of the RTO control areas, thus better enabling market participants to solve loop-flow problems creatively. The NOPR points out that widening the geographic scope for scheduling and pricing will result in "more accurate ATC calculations, improve reliability, and, potentially, eliminate or reduce disputes among transmission providers regarding uncompensated uses of facilities."
One solution to the congestion created by these flows is RTO-facilitated generation redispatch. Redispatch could be coordinated by and through RTOs. Individual sellers need not be burdened with contracting separately with multiple generators and/or transmission providers to arrange redispatch options, the need for which is difficult to anticipate in advance and nearly impossible to coordinate on a real-time basis.
D.
Serve As Supplier of Last Resort for All Ancillary Services
The NOPR proposed that, as a transmission provider, an RTO must provide, or cause to be provided, the six ancillary services required by Order No. 888 and subsequent orders. Since the RTO will not, by definition, own any generating resources, the NOPR recommends that ancillary service providers be subject to the complete operational control, directly or indirectly, of the RTO. RTOs would determine the quantities and, where appropriate, the locations where certain ancillary services must be provided.
EPSA concurs with FERC's requirement that RTOs step into the obligations imposed on transmission providers to supply or obtain ancillary service. EPSA urges FERC to require that, where possible, RTOs use competitive procurements to obtain the ancillary services needed. The Commission's recent order in Avista Corporation, found that "provision of [ancillary services] is a key component in the development of competitive markets." That Order was designed to "encourage entry into the ancillary service markets and promote competition in these markets." While that Order was not applicable to ancillary services provided to RTOs, the underlying concept: promoting competition for ancillary services, should be incorporated into the Final Rule.
E.
Operate a Single OASIS Site for All Transmission Facilities Under Its Control With Responsibility for Independently Calculating the TTC and ATC
The NOPR recommends that RTOs must serve as the single OASIS site administrator for all transmission facilities under its control. As such, the RTO would independently calculate TTC and ATC. This is another important role for an RTO. As the NOPR notes, an RTO will "produce better ATC estimates because it would have access to complete regional usage information, would have current information because the RTO will be the security coordinator as well as the OASIS site administrator, and would calculate ATC values on a consistent regional-wide basis using a regional flow model." EPSA concurs that ATC calculations made within each region by a single entity, using a single set of rules and procedures and real-time information, will improve the value of ATC data in the market.
Confidence in market information is critical, and sorely lacking in today's environment. Information is not posted in a timely manner, ATC is often vastly underestimated by conservative transmission providers, and disappears at the apparent whim of other transmission providers. Having an independent and neutral RTO calculate and post ATC will address many of these concerns. As the level of transmission operations rises (and it appears to be higher today than in prior years), RTOs will need to be ever more vigilant in determining ATC. Assuming steadily increasing demand for power nationwide that is not met by transmission expansion, new technologies, or more efficient operations, congestion is likely to increase and market participants will need to be able to react to this important market condition.
There are also simple information management issues that RTOs will be able to address. For example, transmission customers are often stymied by inconsistent path names and ATC calculations at the same interface. Having an RTO address these issues on a regional basis will help solve some of these problems and minimize or eliminate the current inefficiencies that result when adjacent utilities make inconsistent ATC determinations. In an RTO of sufficient size and independence, the ATC calculations can be performed in a consistent manner across the entire RTO and not be skewed by artificial limitations of small control areas. In addition, RTOs must be instructed to work closely with their neighbors to ensure that new border problems are not created.
It is important to point out, however, that although frustration with ATC calculations may be lessened by RTO formation, they will not be eliminated until all customers (including native load) reserve and schedule transmission service under a single tariff. The heart of the current dissatisfaction with "black box" ATC calculations is the problem of transmission providers' holding back transmission capacity for their own native load and network service. Confusion and uncertainty over the validity of ATC calculations will continue until transmission providers actually have to rely on ATC postings for all their transmission service, not just their wholesale sales.
F.
Monitor Markets to Identify Design Flaws and Market Power
The NOPR posits that RTOs must monitor markets for transmission services, ancillary services and bulk power markets to identify design flaws and market power. RTOs would be responsible for proposing appropriate remedial actions. EPSA agrees that RTOs have an important role to play in gathering information about transmission availability and market operations. The focus of an RTO's market monitoring function should be to provide FERC with technical support and information. A large RTO will have a professional staff that can efficiently and effectively perform this technical support function. RTOs should develop reporting procedures that are designed to collect and publish information about the operation of the transmission system as it affects markets, with the goal of allowing market participants and FERC to determine whether such markets are facilitating competition. The information and market data collected by an independent and unbiased RTO could be relied upon by market participants in formulating business strategies, and by regulators for purposes of reviewing and approving modifications to regulated aspects of RTO structure and operations.
RTOs should have adequate authority to enforce FERC-approved transmission rules as necessary to ensure system reliability and efficient market operations. The RTO also should coordinate the administration of alternative dispute mechanisms. However, EPSA is concerned about the Commission's use of the term "light-handed" regulation. RTOs should not be established as, or transformed into, quasi-regulatory bodies with ongoing authority to investigate the market activities of industry participants, or to sanction behavior it deems inappropriate. This is specifically the responsibility of FERC.
Certainly, the RTO should not be empowered to sanction the bidding practices of a particular market participant based solely on its unilateral belief that such practices may be unduly discriminatory or otherwise evince the exercise of market power. The latter requires making subjective determinations about the competitive practices of market participants and would constitute an unwarranted and unnecessary intrusion into market operations. Rather, to the extent an RTO questions the business practices of any participant, it should have authority to raise such action at an appropriate forum, e.g., FERC. Nor should an RTO have unilateral authority to impose price caps or other measures designed to affect market rates. Under the Federal Power Act, only the FERC has authority to determine just and reasonable rates.
Perhaps more importantly, RTOs must not use "reliability" as an excuse to address what may be perceived as market failures but are actually the normal functioning of the market. High prices during some time periods are generally signs that the market is signaling the need for additional capacity (or reduced demand). These times should not be seen by the RTO as signals that it need apply Draconian methods to "maintain reliability." If the RTO believes that the market is not responding properly, the RTO may be in a position to provide information on market behavior confidentially -- in the manner of a "grand jury" -- to FERC so that the Commission can then investigate the issue and report on the potential transmission-related (or other) causes. The RTO should not be empowered to remedy the situation through market intervention unless it has the potential to become catastrophic - a true emergency.
RTOs that are not reticent about stepping into markets will chill resolution of problems by those market participants directly affected. An example is in the area of generation adequacy, which is oftentimes characterized as a reliability issue, but is in fact a mismatch between purchasers' and suppliers' views of the adequate level (and cost) of supply. RTOs may need to examine why incentives are not adequately aligned and what changes to market rules may be necessary to create better alignment (e.g., do load-serving entities have appropriate incentives to purchase adequate supplies for their expected load?), but should make every effort to avoid out-of-market solutions, such as offering contracts directly to suppliers for new generation. While the latter might seem an appropriate short-term fix, the implications for future market operation are ominous.
Accordingly, while RTOs should have market monitoring and emergency mitigation functions, they should be required to exercise their authority within the strict confines of the regulatory oversight provided by FERC. RTOs should limit their activities to data gathering and investigating transmission-related complaints and then reporting their findings to FERC for final disposition.
G.
Plan and Coordinate Necessary Transmission Additions and Upgrades
The NOPR posits that RTOs must be responsible for planning necessary transmission additions and upgrades that will enable it to provide efficient, reliable and non-discriminatory transmission service. EPSA agrees that an essential role for RTOs is transmission coordination and planning. RTOs should be responsible for conducting the studies necessary to assess the need for new transmission system enhancements and conducting system impact and other studies for new generation interconnections. Such system enhancements should take into account new entrants into the market, and the level of upgrades, if any, for which the new entrant is responsible.
As the NOPR points out, RTOs should be able to see the "big picture" and eliminate planning and expansion of grid facilities "on a piecemeal basis." To ensure fairness, this requires clearly defined study criteria and a predictable and fair construction sequencing process. There must be clearly defined rules as to whether new market entrants have the same transmission rights as existing generators and other transmission customers.
Moreover, RTOs should facilitate market participants' efforts to expand the generation and transmission systems, to the extent desired, beyond what may be necessary merely to maintain safe and reliable service. Third-party, non-transmission owning, private investors may wish to make transmission investments in exchange for receiving the value and rights associated with their investments. Expansion projects should be allowed to be undertaken, with appropriate RTO coordination, by the parties who will benefit from the system's expansion. This direct involvement of the benefiting party creates a market control over the decision to expand the transmission system. While benefiting parties would receive valuable consideration, in terms of transmission rights or otherwise, from the RTO as reimbursement for their investment, each would have measured the size of this benefit against the cost. Decision making of market participants would thus act as a market-based check on the RTO's planners. Still, RTOs should ensure that system improvements benefiting certain parties do not unduly impact other parties. RTOs should be charged with efficiently balancing the competing desires of various market participants, with FERC as an appropriate backstop in the event the RTO cannot amicably resolve certain issues.
The above conditions apply equally to an ISO and a Transco structure. The Transco, however, brings the capability of itself investing in transmission upgrades that will reduce the Transco's operating costs through increased transfer capability. This provides a means of assuring that the market will be structured to assure that transmission investments are efficiently traded off against generation investment.
Given the discussion above, routine investments to mitigate congestion should not be made exclusively by an RTO, but should be permitted by market participants. RTOs can potentially preclude adequate market responses by developing plans to mitigate congestion ahead of the market. System expansion may benefit many members of an ISO, but no particular set of users sufficiently to undertake the necessary investments. Similarly, there may be investments in technological or operational innovations available to the RTO - specifically the Transco -- that could be alternatives to physical expansions of the transmission system. These investments would benefit the owner/operator of the Transco, as well as all transmission customers.
Siting of transmission has become the principle impediment to transmission expansion. The RTO should be delegated sufficient authority to direct transmission owners or others to exercise their eminent domain authority, as necessary, to implement transmission system expansion plans independent of the source of funds or the beneficiary of the project. Under current law, this authority must come from the states. As discussed below, however, EPSA supports enactment of federal legislation providing FERC authority over system planning and jurisdiction over transmission siting approvals.
To the extent that market participants in a given region elect to pay for new transmission upgrades, spec