FERC Filings
COMMENTS OF THE ELECTRIC POWER SUPPLY ASSOCIATION ON THE OPTIONS PAPER FOR RESOLVING RATE AND TRANSITION ISSUES IN STANDARDIZED TRANSMISSION SERVICE AND WHOLESALE ELECTRIC MARKET DESIGN
BODY
As noted in earlier comments, EPSA fully supports the Commission’s initiative to provide all transmission customers the ability to select Network Access Service (NAS). This option will go a long way in creating comparability between the transmission service used by incumbent utilities serving native load customers and other transmission customers and transactions. Further, NAS will help eliminate the discriminatory treatment with respect to deliverability that merchant generators and marketers experience when compared with load-serving transmission owners. While endorsing the creation of this important new option, however, EPSA urges the Commission to retain flexibility in the new tariff by providing other service options. The Commission should specifically retain the option to self-schedule, as well as the option of point-to-point service through an RTO in addition to point-to-point export service to another RTO, as outlined in the Staff Working Paper of March 24, 2002.
The April 10th Options Paper focuses on four issues critical to the success of the Commission’s initiatives. EPSA is pleased the Commission has highlighted these important issues, resolution of which is needed to allow the industry to move forward. EPSA’s comments address each of the issues identified in the paper. EPSA also applauds the Staff’s heroic efforts to identify options on each of these issues. On many issues, however, more creativity and industry effort will be needed, as the best solutions may be some combination or refinement of the options identified by the Staff.
1. Recovery of Embedded Cost
The Options Paper asks three questions about the recovery of embedded cost. While each is a separate question, the issues are closely interrelated. It is important to keep sight of the underlying goal: elimination of pancaked rates within each RTO. EPSA supports the premise that rates must be designed to ensure that legitimate revenue requirements are collected. However, the benefits to consumers come when competition is based on the value of generation, not a myriad of inefficient transmission charges and uplift costs that artificially obscure the cost of power. Thus, any system that guarantees recovery of current embedded costs must transition, over a short and defined period of time, to eliminate revenue guarantees. EPSA would urge that this transition period range from three to five years.
Who pays the access charge for deliveries within the transmission provider’s system?
Access charges are intended to collect the transmission owners’ revenue requirement, and thus should be paid by those entities for which the transmission grid was initially designed and built – those taking power off the grid in a specific RTO region. Therefore, EPSA believes that the adoption of Option 2 is the most appropriate solution. In most instances, a utility’s full transmission revenue requirement should be allocated to those customers. Wholesale transmission revenues collected from those delivering power into the system or wheeling through the system (see below) should be credited to load to offset those costs.
Should the access charge apply to exports and wheelthroughs?
The short answer is no, because this option perpetuates pancaking. The longer answer is a bit more involved, of course. How to best accomplish the policy articulated above is a very difficult problem, particularly without knowing how rates will be designed. Each of the options identified in the Options Papers has serious drawbacks, and the ultimate answer is likely to be some modification or amalgam of the ideas outlined. To address this, it is important to focus on the Commission’s goals. The primary goal is to eliminate or minimize rate pancaking so that robust competition for wholesale power can occur. At the same time, the Commission must acknowledge and address a series of problems, including overcharging market participants, barriers to entry, streamlined inter-RTO administration and the “free rider” problem. It is also important to differentiate access charges from other costs associated with the use of the transmission system, which wholesale customers will pay. As RTOs take hold and their footprints expand, these transition problems are inherently minimized.
Clearly, minimizing transmission costs will broaden commodity markets and allow more direct competition for the wholesale commodity. In addition, incentives for RTOs to move power will send the right signals to maximize efficient use of the transmission system. Simplicity, certainty and transparency are also important for markets to operate well and may speed the transition.
To balance equity and efficiency, the Commission might consider imposing a “wheelthrough” charge in lieu of an access charge for exports and wheelthroughs. This charge would be designed to recover a small percentage of the embedded costs of the transmission system, perhaps tied to power flow studies showing increased flows resulting from less seams and less constrained markets. One current study in the Midwest indicates that such a percentage would be in the range of 10 percent. These exports and wheelthrough charges should not be so onerous that transactions are made uneconomic. Additionally, if access charges are imposed on exports and wheelthroughs, the Commission should encourage discounting for those transactions.
Is the access charge billed based on peak load or total usage?
Again, each of the options presented raises different advantages and disadvantages, and a focus on the underlying goals may be important to make the necessary calls. In addition, it may be difficult to make a final call here without knowing how the rates will be designed.
From EPSA’s perspective, the most important consideration is to make the access charge predictable and easier to calculate for the customer. To achieve this goal, there may be an inherent trade-off between correct allocation of cost responsibility and familiarity with the current 12-coincident peak methodology.
Generally, the transmission system is sized to meet the peak demand of retail load. While the discussion of the options focuses on peak demand and the impact of access charges on high or low load factor customers, system usage by most wholesale transmission customers is less correlated with coincident peak demand. To the extent that wholesale customers – marketers or generators – pay the access charge, their impact on peak usage is indirect. Therefore, if the policy objective is to minimize undue impacts on one class of customers (e.g., high-load factor) vis-à-vis another class (e.g., low-load factor), it may be necessary to compromise – perhaps by staying with the current monthly peak methodology. Regardless, it is important, however, for retail rate design to focus on sending the right price signals to encourage the type of demand response anticipated by the new SMD. It is also important that the Commission not adopt a methodology that creates barriers or disincentives to retail choice programs.
2. Transition of Customers Under Existing Wholesale Contracts and Bundled Retail Customers Load to Transmission Service Under the Revised Pro Forma Tariff
This question raises one of the most significant aspects of the Commission’s Standard Market Design initiative: the ability to finally eliminate the residual discrimination that has plagued – and continues to plague – the transmission system. As the Commission has repeatedly recognized, the ability of transmission owners to favor their own generation creates an irresistible incentive to discriminate in the management and operation of the transmission grid. As EPSA has repeatedly stated, a single tariff for all transmission service is the only effective way to eliminate this discrimination. Ultimately, the elimination of residual discrimination will occur only when all uses of the transmission grid are under the same rate schedules, terms and conditions. With actual comparability, the transmission owner’s interest would be to operate the grid as a stand-alone business and maximize throughput, rather than to use transmission to increase the return on its investment in power generation, marketing and sales. A single, system-wide transmission tariff will allow all load-serving entities, whether they are the current incumbents or new market entrants, access to the lowest-cost supplies to meet their customers’ needs.
Getting from here to there as quickly as possible is a critical challenge. EPSA strongly endorses the adoption of Option 1, which requires that all transmission users take service under the new, single open access transmission tariff at the time the standard market design is implemented. As the Commission well knows, significant benefits will accrue to consumers from a robust competitive electricity market and the significance of the current problem with unequal transmission access should not be underestimated. In the original RTO filing made by the Southwest Power Pool (Docket No. RT01-34-000), as much as 92% of existing transmission service, mostly for native load service, would have been exempt from the RTO’s OATT. Continued delays in getting to a competitive market costs customers money every day. EPSA urges the Commission to send the clearest possible signal to the industry that the prolonged transition to a system of truly open access to transmission is over and that all transmission use must take place under a single tariff.
If, however, the Commission decides not to adopt Option 1, EPSA strongly urges the Commission to require that all transmission service for native load customers be taken under the new tariff immediately. To the extent that some clearly defined and limited transition period may be allowed for converting existing wholesale transmission contracts, the transition should be only for explicit contracts, not the implicit contract underpinning native load service.
3. Allocation of Transmission Rights
In comments filed on the Commission’s March 15th Working Paper, EPSA lauded the Commission’s recognition of the importance of Transmission Rights (TRs) as a necessary component of successful and efficient congestion management systems and as a way to help send the right signals for new infrastructure and for price certainty. Ultimately, the goal is a level playing field for all transmission customers.
Should historical customers get the initial Transmission Rights?
If existing customers are given the initial conversion rights, how should Transmission Rights be allocated?
Unfortunately, this is one area where the Options Paper is not as clear as it could be. Embedded in the discussion of the first question is an option EPSA believes is the right approach: an allocation of the auction revenues for Transmission Rights. The Options under the second question have led to confusion as well. EPSA supports an approach that assigns initial TRs auction revenues to historical customers based on existing contract rights. Again, the Commission is faced with potentially competing goals: ensuring that customers with existing contracts receive the same level and quality of service they’ve always had (and that they’ve paid for) and promoting an efficient marketplace that allocates transmission to those who value it accordingly. The use of auction revenue rights rather than direct allocation of TRs best achieves both of these goals.
The allocation of auction revenues allows TR holders who wish to retain those rights to keep them. By bidding an extremely high price, which is “paid” to themselves, TR holders can be sure of retaining those rights they value and wish to use. However, should other buyers value those rights more highly, a more efficient allocation of TRs will result. This approach will ensure that all TRs are included in the auction, which creates more liquidity and efficiency than a residual-only market which will result from an allocation approach.
The experience of financial congestion rights in NYISO and PJM demonstrates that an auction process is preferable to allocation. Given the importance of TRs to the success of competitive electricity markets, the Commission should adopt the auction approach to TR allocations.
4. Long-Term Generation Adequacy
Ensuring generation adequacy in competitive markets is another critical issue in SMD. While many believe that an energy-only market could set the price signals necessary for a reliable system, others are concerned about the lag time between price signals and new construction. Still others are concerned that the political appetite for the price volatility needed to establish price signals for new investment is lacking. Certainly, as long as elaborate price mitigation protocols and supply offer caps (as a proxy for demand response) remain an institutional feature of wholesale electricity markets, emerging RTO markets and the SMD, the Commission will need to find ways to send adequate signals to ensure generation adequacy. Well-designed energy markets, coupled with an affirmative capacity market that allows for recovery of capital costs, can help accomplish that goal. This design must balance the near-term planning horizons, which are a feature of developing retail markets where load responsibilities shift from month to month, with the longer-term planning horizon necessary for generation construction.
As stated in earlier comments, EPSA believes there should be a binding, long-term obligation for load-serving entities to procure, through bilateral contracts or otherwise, adequate capacity resources to deliver energy on demand. It is very important that capacity obligations not create unwarranted advantages to incumbents or create barriers to new entry in wholesale or retail markets. Parties need flexibility in determining how capacity obligations can be met, pursuant to established standards for both generation and load. Suppliers need to be compensated for providing capacity-related services, such as call options and recall options, required to sustain generation adequacy.
It is difficult to select among the Options presented, as each is lacking in certain premises and details, and each appears predicated upon one of the existing approaches, none of which has been universally satisfactory. The best approach may be to select from aspects of each of the options presented to accomplish the underlying goals.
As the Commission is aware, there is a Joint Capacity Adequacy Group in the Northeast working on this issue. The group involves a broad section of industry participants from the three northeastern ISOs. While the efforts of this group remain a work in progress, the Commission should take its efforts into account and consider incorporating the proposals developed by the group in any notice of proposed rulemaking on SMD. There are several straw proposals for capacity markets now under consideration that encompass the key elements identified in the Options Paper, plus other requisite components not mentioned.
Any capacity market/regional capacity obligation adopted by the Commission for SMD should meet certain objectives:
- Ensure that adequate generation (and transmission) is either on-line or in reserve to reliably deliver energy, as defined by agreed-upon standards, at the lowest reasonable total cost.
- Use a quantitative (e.g. probabilistic) method that accounts for all the factors that affect reliability to determine the level of resources required to achieve a defined standard for determination of bulk power system adequacy (e.g. provision of sufficient resources to meet one in 10 LOLP).
- Define buyer and seller obligations in a manner that accommodates retail choice where available. Employ an equitable method to allocate the pool resource obligation.
- Quantify multiple resource options (e.g. operating plant, future plant, capacity purchase, interruptible load, firm energy/call option with appropriate back-up) and the impact of transmission expansion to meet the resource obligation. Use a quantitative method to determine a capacity value for each resource option and establish criteria to qualify as satisfying an obligation. The quantitative methods should treat internal and external resources in a non-discriminatory fashion.
- Rely on market mechanisms to establish values to incent satisfaction of obligations and penalize non-compliance.
- Make RTO/ISO market transactions transparent to facilitate market monitoring and mitigation.
- Ensure that the forward market value of capacity will provide appropriate price signals to sustain adequate levels of generation, demand response and transmission to meet forecasted reliability requirements.
- Address the seams issues associated with capacity obligations among and between RTOs/ISOs (e.g. PJM and MISO or PJM and PJM West).
- Operation of the model must produce solutions and incentives that are consistent with the development and operation of robust, competitive and non-discriminatory wholesale and retail electric markets.