FERC Filings
Request for Rehearing and Clarification of the Order on Rehearing and Modifying Interim Generation Market Power Analysis and Mitigation Policy of EPSA
Issues
1. The Industry Needs Greater Clarity
The Commission¡¦s Order announces two new tests for generation market power, the Pivotal Supplier Analysis (PSA) and the Market Share Analysis (MSA), which are, in fact, no longer tests but ¡§indicative screens.¡¨ This represents a huge leap in both sophistication and complexity in assessing generation market power. In addition, the multiple ¡§on-ramps¡¨ and ¡§off-ramps,¡¨ which allow applicants to make and intervenors to challenge various analyses and tests, and to make creative alternative proposals at various stages of the proceeding, represent a quantitative leap in administrative complexity.
Under the Commission¡¦s Order, applicants must make showings that require complex models, sensitivity analyses, rebuttable presumptions and alternative screens. In today¡¦s world, those exercises are as much art as science. The models contemplated by the Order require huge amounts of data, some of which is not available and much of which is difficult to obtain or verify, as well as numerous assumptions, which may or may not be commonly shared. Then, intervenors can challenge applicants¡¦ proposals or rebut presumptions, requiring their own complex and sophisticated analyses to do so. The costs associated with these undertakings are staggering.
In the Order, the Commission properly recognizes the need for regulatory certainty and strives to balance that need with the appropriate level of flexibility. However, the Commission also needs to recognize that, at least in some cases, the very analyses it expects to review are not well established or commonly accepted. For example, there is no commonly established definition of a load pocket needed for the assessment of geographical generation market power. In other proceedings, the industry has argued over whether load pockets are defined by transmission constraints, supply shortages or market dominance by a single supplier.
In any market power or merger analysis, models are routinely customized to reflect various assumptions and expectations, which in turn shape the outcome. Without well-established and generally accepted frameworks for the analysis now required, parties can, and will, develop dueling studies that do little to resolve the underlying problem of whether or not generation market power exists.
The Commission cannot underestimate the huge costs and administrative burden imposed by this new approach. This is particularly true for those market participants that do not have captive customers from which to recover the costs associated with expert witnesses, model development, model runs, and other litigation expenses.
For this reason, EPSA urges the Commission to do a ¡§trial run¡¨ of its new market power screens, applying them only to a small subset of companies, so that the industry can develop more familiarity and confidence before such complex and sophisticated tests set out in the Order are generally applied. The Commission could start with the three companies that gave rise to this proceeding on a non-generic basis. These companies are required to submit revised triennial updates using the new screens within 60 days of the Order and these updates could serve as a useful test of how these new analyses will actually work in practice. This will allow these three companies, the Commission and the industry to efficiently and effectively gain more familiarity with the analysis underlying the new approach. This trial process could also inform the rulemaking proceeding, so that any final screen adopted in this proceeding would be well-tested, more robust and accepted by the industry.
2. The Commission Should Not Penalize Market Participants That Are In An RTO
Because of the extensive market monitoring in RTO and ISO markets, and the Commission¡¦s Market Behavior Rules which require compliance with RTO market rules, EPSA has supported the exemption for RTO and ISO participants in previous market power screens and would support a continued exemption under these new screens. In addition to intensive market surveillance and monitoring, RTOs create a structural remedy to address market power concerns. Where structures are already in place to identify and mitigate market power, expending unnecessary resources to duplicate that effort is inefficient for both the Commission and the industry.
In addition, under the process as currently designed which addresses both screens and mitigation, the Commission runs the very real risk of creating dueling approaches to mitigation within an RTO market. For example, under the Order, an applicant in an RTO might propose mitigation measures, some contemplated by this Order, others not, that are inconsistent with the Commission-approved RTO mitigation program. This would be very disruptive to the RTO¡¦s market monitoring program. Conversely, could applicants that passed the generation market power screens be exempt from RTO monitoring and mitigation? Where RTOs have designed, and the Commission has approved, market mitigation programs, imposing overlapping and potentially inconsistent mitigation requirements will have unintended consequences of skewing market results and disrupting market outcomes.
Even without an exemption, however, EPSA has two recommendations. First, applicants within RTOs should be entitled to the same flexibility as those outside RTO markets to expedite their market-based rate applications by accepting RTO-imposed mitigation. Second, for entities within RTO markets, the Commission should assess the competitiveness of the market itself, rather than focus on a market power analysis for each individual market participant. At a
minimum, critical assumptions and inputs to the generation screen should be available from the RTO.
On the first issue, it is essential, particularly given the discussion above about the complex, expensive and resource-intensive nature of these new generation market power screens, that the Commission permit applicants within RTO markets to accept a presumption of market power and move directly to appropriate mitigation. In eliminating the ¡§RTO exemption¡¨ the Commission has failed to clearly state that market participants in RTOs have the same options as those who are not in RTOs. While the Commission allows an applicant to ¡§point to RTO mitigation rules as evidence that this market power has been adequately mitigated,¡¨ it can do so only as part of its market power analysis. This has the potential to produce patently unfair results, penalizing market participants by imposing expensive and time-consuming requirements that those outside RTOs can avoid. RTO participants should have the same option as non-RTO participants to simply accept RTO mitigation without completing the screens.
In addition, the Commission should adopt a different approach to assessing generation market power within RTOs. Individual market participants should not be placed in the position of analyzing organized markets and having to justify or criticized Commission-approved monitoring and mitigation programs. Rather than focus on individual market participants, the Commission should look at the overall competitiveness of the RTO market. Using the RTO/ISO footprint as the appropriate geographic market for RTO/ISO participants, the RTO could help streamline this process by performing an indicative screen analysis for the market as a whole. The Commission¡¦s current approach to analyzing market power on an applicant-by-applicant basis was developed before the advent of organized markets. Within those markets, it makes little sense to continue this practice. EPSA recommends that RTOs with organized markets and Commission-approved mitigation be required to perform screen analyses for their markets as a whole on an annual basis and no longer require applicant-by-applicant submittals. To the extent market power issues are present, RTOs will be in the best position to address whether any changes in market structure or mitigation measures are needed.
At a minimum, to streamline the process and promote consistent analyses, the Commission should require RTOs and ISOs to post the critical inputs for the SMA analysis so that all participants in those markets can use comparable data in making their applications. The critical inputs include: nameplate generating capacity within the footprint, annual peak load day and amount (i.e., needle peak), daily average peak demand during the month the peak load day occurs, minimal peak load day for each season, simultaneous import capability, operating reserve and planned outages. Not only will it be inefficient to require each market participant to develop the numbers itself, doing so will inevitably result in inconsistent analyses that the Commission will have to reconcile.
3. The Screens are Unrealistic and Must Be Revised
In earlier comments in this proceeding, EPSA urged the Commission not to exclude committed capacity from any market power screen. There are several significant reasons EPSA urges the Commission to reconsider the approach taken in this Order. The indicative screens are totally inconsistent with the Merger Policy Statement which identifies economic capacity (which the Commission describes as the analog to installed capacity ) as the ¡§most important¡¨ measure of a supplier¡¦s presence in a market and indicative of which suppliers have a pronounced competitive advantage. The Commission¡¦s approach in the Merger Policy Statement is superior for important reasons.
First, excluding both native load and the capacity assumed to serve it ignores the reality that capacity cannot be segregated between wholesale and retail and that native load itself constitutes the bulk of the potential wholesale market because its needs can be purchased at wholesale.
Second, excluding native load and the capacity that is assumed to serve it will create ¡§false positives¡¨ for market power. Large amounts of merchant generation which have been foreclosed from the market will be counted as uncommitted capacity and assumed to be competing supply for a small amount of wholesale load, i.e., the difference between the average peaks and the needle peak. The result will be that the very companies which the Commission is trying to incent to enter markets will incorrectly appear to be dominant firms. Even if these companies do not fail the indicative screens for their own market-based rate authority because their plants were built after July 9, 1996, a set of metrics which shows supply exceeding load many times over is at odds with the reality. Merchant generators installed their generation to compete for all load at wholesale, including wholesale sales to ultimately serve native load; not for a few megawatts of residual wholesale load, mere ¡§crumbs¡¨ of a competitive wholesale market, which the screens take into account. The Commission¡¦s approach so artificially shrinks the size of the competitive wholesale market that, outside RTOs and ISOs, the wholesale market will represent only a very small percentage of the actual market, in some cases only 10 to 20 percent of the total market.
The screens are fatally flawed and EPSA recommends that the Commission revise the screens to reflect the reality that wholesale and retail supply and wholesale and retail demand are fungible and cannot be easily separated.
4. What is the Right Approach to Mitigation?
At the outset, EPSA shares the Commission¡¦s preference for structural rather than behavioral solutions. As discussed in previous comments, EPSA urges the Commission to put in place interim structural remedies designed to serve the twin goals of creating ex-ante mitigation protocols and facilitating the development of RTOs and ISOs that will diminish the potential for the undue exercise of market power. EPSA is hopeful that these structural remedies will be the focus of the companion rulemaking proceeding.
Even in this proceeding, however, EPSA urges the Commission to focus its mitigation tools for generation market power on solving the problems that exist today, starting with careful scrutiny of all inter-affiliate transactions. It is through the use of affiliate transactions that dominant players are most likely to continue to exercise their market dominance and the remedy imposed should be tailored to solve that problem effectively. The Commission should also preclude any affiliate transaction unless there was an effective competitive procurement program in place to test the competitive alternatives and ensure that the affiliate transaction is the best deal for wholesale customers.
In addition, EPSA has urged the Commission to put an independent entity in place to administer certain transmission functions for those vertically integrated utilities and their affiliates that do not pass the SMA screen. The OASIS site should be operated by a third-party entity, which should also be responsible for calculating and posting TTC and ATC. That entity should also manage or oversee the process of performing transmission studies needed to handle interconnection requests. Further, the Commission should require transparent operation of the transmission system, which may require the services of an independent third-party entity to monitor operations.
Finally, the Commission should focus on mitigation measures that encourage new entry and promote continued market development. One example, which can be imposed on both short and long-term transactions, is competitive procurement, requiring a dominant entity to engage in a competitive solicitation process if it proposes any affiliate transactions. This will encourage new entry and ensure the best possible deals for utility consumers.
As noted in earlier comments, EPSA is very concerned about any mitigation that caps sales at ¡§cost-based¡¨ rates. While cost of service is a long-standing regulatory tradition, it is not at all clear what costs would be included in these cost-based rates, what the process would be to determine them, and what products they would apply to. The Commission cites to an established body of precedent for determining cost-based ceilings, but that precedent involved opportunity sales by vertically-integrated utilities which would simply generate revenue credits to defray the fixed costs being fully borne by captive ratepayers. Merchants have no captive ratepayers who are obligated to pay their fixed costs and any default rate must reflect this reality.
Similarly, the Commission¡¦s use of incremental cost plus 10 percent for sales of one week or less is flawed. There is absolutely no relationship between a generator¡¦s incremental cost and its fixed costs. Moreover, the Commission¡¦s reliance on PJM is misplaced. Generators dispatched out of merit order in PJM have their bids capped at 10 percent, not their prices. Those generators receive the market-clearing price whenever it exceeds their capped bids. The Commission¡¦s approach in this order limits a generator¡¦s ability to fully recover its costs in ways that PJM¡¦s approach does not. As such, the Commission¡¦s proposal for mitigating sales of one week or less
could constitute a confiscatory rate and should be withdrawn. However, if cost-based mitigation is retained, the Commission should be sure generators are provided an opportunity to fully recover their cost of service.
More significantly, mixing cost and market-based rates creates perverse incentives. As we saw in California, any effort to slice and dice markets for different products, services or participants, and impose cost-based rates for some of them, can lead to bizarre and unanticipated results. For example, if cost-based rates are imposed for certain ancillary services, but market prices are allowed for energy services or other ancillary services, companies are likely to pursue strategies to move energy from one market to another in order to receive the higher price, creating huge distortions and potential reliability problems.
It is also important to remember that conceptually, cost-based rates serve as both a floor and a ceiling, as they represent the long-term costs ratepayers are obligated to pay. Thus, they are difficult to impose in shorter-term markets. Finally, experience has shown that cost-based rates do little to replicate or promote competitive markets and do nothing to cure the fundamental problem of excessive generation concentration.
Another problem with a cost-based approach to mitigation is that it is often focused on solving the wrong problem. Properly structured price and offer caps, in conjunction with well-designed capacity markets, may make sense when the concern is that dominant suppliers will exercise market power through economic and physical withholding. There is little or no basis in this record to conclude that dominant entities in the electric industry routinely exercise market power through economic or physical withholding. However, there is considerable evidence that dominant entities in the electric industry routinely exercise market power by foreclosing access to the market by their competitors (i.e., restricting supply entry).
Thus, it is important that the Commission tailor the remedy imposed to solve the existing problem. As discussed above, imposing cost-capped rates on the dominant entities will do nothing to encourage new entry or market development and it may, in fact, cause considerable harm to those goals. In addition, cost-based rates raise problems of their own, when state-regulated utilities are able to assign the vast majority of their costs to their captive rate base, with a guaranteed return, leaving them free to compete in the wholesale markets with what are essentially subsidized rates when compared to other suppliers without those options. While lower wholesale rates may be initially attractive, they are not ultimately sustainable as competitors are forced from the market, leaving the dominant supplier free to raise rates without competitive checks.
This is an area where other approaches to mitigation might be particularly effective. For example, the Commission could require utilities to mitigate their market power by engaging in well-designed competitive procurement practices and economically dispatching their systems in a manner that allows all generation to compete to serve load.
5. Suppliers Lack Access to Necessary Information
As noted above, the approach adopted by the Commission in the Order requires complex, sophisticated and expensive modeling and analysis. One immediate problem is that the information necessary to undertake these new requirements is not always available to the applicant. For example, outside of RTOs, applicants must show that they do not have market power in the control area where they are located, which allows consideration of generators in adjacent control areas that are able to supply power that does not exceed the simultaneous transfer limit (STL). While it may be reasonable to ask utilities to test for simultaneous transfer limits, competitive power suppliers simply do not have access to the information needed to complete that analysis.
One option would be to have all transmission providers post and maintain their seasonal simultaneous transfer limits on their OASIS. Alternatively, given the lack of available information, competitive power suppliers should be able to use the Total Transfer Capability (TTC) as a proxy for the amount of uncommitted capacity in neighboring control areas. Items that would limit TTC, such as transmission reliability margins and capacity benefit margin, would ordinarily be assigned to the market share of the incumbent vertically integrated utility. Thus, as a simplifying assumption, allowing competitive suppliers to use TTC will not underestimate their overall market share.
Similarly, the Order requires that operating reserve requirements be based on state and reliability council requirements. However, these requirements are not always generally known and are often defined in terms of reliability criteria (e.g., loss of load probability of one day in ten years or single largest contingency) rather than as a percentage of generation or load. The Commission should require each transmission provider to post its current operating reserve requirement and state that requirement as a percent of generation or load.
A similar problem exists with respect to an applicant¡¦s ability to adjust competing suppliers¡¦ capacity to reflect planned outages. Data on competitors¡¦ planned outages is not always available, except to the extent it appears in FERC Form 714, which does not appear to be in a format that allows the computations required in paragraph 100. Form 714 only lists planned outages and plant deratings for the peak hour of each month and it does so on an aggregate control area basis, rather than an individual unit basis. The Commission should be clear that information that is not publicly available cannot be a required element of a filing. In addition, planned outage information introduces another level of complexity and difficulty in completing the required studies. Thus, even where it is available, the Commission should allow planned outage data to be an optional element of a filing.
It is quite likely that other data issues and problems will arise in the practical implementation of the screens. The test-run proposal outlined above could serve to identify these issues and allow the Commission to refine and resolve them before they preclude parties without market power from satisfying the Commission¡¦s generation market screens. At a minimum, the Commission needs to clarify its requirements and provide better guidance to those entities required to undertake studies and make showings involving information that is not under their control.
6. The Commission Should Clarify the Section 35.27 Exemption
The Order reiterates that Section 35.27 of its Regulations exempts utilities seeking market-based rate authorization from demonstrating the lack of generation market power for capacity for which construction commenced on or after July 9, 1996. However, the Order cautions that, if an applicant sites or acquires generation in an area where it or its affiliates own or control other generation assets, the applicant must address whether its new capacity raises generation market power concerns when added to the existing capacity.
EPSA requests that the Commission confirm that no generation market power demonstration is required even when an applicant or its affiliates own or control multiple generation if construction commenced on all such generation in
the relevant market after July 9, 1996.
Further, the Commission needs to clarify the term ¡§area¡¨ when it requires applicants to include other generation in the ¡§area.¡¨ Specifically, the Commission needs to address the following issues:
„X If an applicant has a single plant in a control area that qualifies for the post June 9, 1996 exemption, would existing facilities owned by the applicant or its affiliate in the adjacent control areas require the applicant to perform the screen in the control area where its otherwise exempted plant is located?
„X Is transmission ownership relevant to this analysis?
„X Does it matter whether the capacity in the adjacent control areas is committed or uncommitted?