FERC Filings
Motion of the Electric Power Supply Association for Leave to Intervene and Comment on the Midwest Independent System Operator's Open Access Transmission and Energy Markets Tariff Filing
Comments
EPSA is encouraged by much in the filing, including the framework proposed in the TEMT for a security-constrained, centralized bid-based scheduling and dispatch system through day-ahead and real-time markets, a market-based mechanism for managing congestion with Locational Marginal Pricing (LMP) and Financial Transmission Rights (FTR). If effectively implemented, this framework holds the promise of robust, non-discriminatory power markets that will bring the benefits of competition to Midwest electricity consumers. However, below are several critical issues that raise concerns, requiring the Commission’s special attention to ensure the most effective implementation of the MISO’s energy market proposal.
A. Multi-Control Area Structure
The multiplicity and relative independence of control area operators within the MISO footprint distinguish the MISO RTO formation effort from those that have emerged from tight power pool arrangements. Of particular concern are issues relating to the shear number of control areas within the MISO footprint, delineation of functions between the MISO and its multiple control area operators and the definition and coordination of responsibilities relating to the procurement of ancillary services and, more important, to accountability for short-term reliability. As noted in the Executive Summary to the TEMT, the Commission “expressed concern over the split of transmission and control area functions” as early as its original order on September 16, 1998, declaring that the MISO satisfied the requirements of Order No. 888. (Original Order).
In the Original Order, the Commission specifically noted the requirement contained in the Midwest ISO Agreement that the MISO prepare and file an assessment report examining “the relationship between existing generation control areas and the Midwest ISO to determine whether the relationship needs to be revised to better assure reliability and to provide nondiscriminatory transmission service.” However, in the February 24 Order, the Commission approved the MISO’s plan to proceed with the centralized operation of a multi-control area market, as well as individual control area procurement of regulation and operating reserves.
The language the Commission used in the February 24 Order represents a de facto postponement of control area consolidation and the MISO’s ultimate control over all aspects of ancillary services. The control of all essential market functions must be brought under centralized, independent authority as soon as possible. Events subsequent to that Order highlight operational difficulties and potential risks suggesting that such a large number of autonomous control areas in a single market region no longer may be practical.
The August 14 blackout and the ongoing investigation of its causes provide a dramatic and urgent context for the Commission’s consideration of the viability of key aspects of the multi-control area structure described in the TEMT. Ironically, on August 1, 2003, the MISO filed the assessment report concluding that "[t]he current multiple Control Area configuration has not imperiled the ability of the Midwest ISO to exert operational control or to insure short-term reliability." While the causes of the August 14 blackout have not yet been established, the chronology of inter-control center communications that have been made publicly available raises serious questions regarding the MISO’s operational interaction with and control and authority over, individual system operators within its footprint. The performances of the various entities involved in the August 14 blackout present compelling questions regarding why certain system operators were able to contain the cascading effects of the blackout while others were not. It would be wise, therefore, to reexamine the basis for delaying the transfer to MISO of all the authority necessary to ensure short-term reliability, system security and control over the ancillary services markets.
Indeed, the Commission itself recognizes that, while an incremental approach may be “appropriate” given the large geographic scope of the MISO’s market, “we have concerns with the Midwest ISO proposal as it relates to the efficiency of the markets and the ability of the Midwest ISO to independently administer the markets.” With respect to ancillary services, EPSA shares the Commission’s concern that “the efficiency of the multi-Control Area market for energy could be compromised if individual utility control areas make inefficient reserve capacity decisions or even unnecessarily withhold capacity from the energy markets on ill-defined reliability grounds.”
The description of the intended MISO-control area relationship contained in the Operational Issues section of the TEMT’s Executive Summary presents a detailed roadmap. Citing FERC regulations, the MISO correctly points out the scope of its RTO responsibilities and obligations, particularly those relating to coordinating control area actions, establishing and coordinating consistent facility outage and maintenance schedules, ensuring that adequate ancillary services are provided and performing all the tasks necessary to maintain short-term reliability.
However, while the MISO will exercise centralized oversight over particularized functions, the individual control areas retain substantial autonomy with respect to the procurement of vital ancillary services, as well as reliability-related matters. EPSA is especially troubled by the extent of the control areas’ authority over the procurement of regulation and operating reserves described in section 38.5.4 of Module C. In the absence of established, clear standards, leaving control areas as the Providers of Last Resort for these services creates incentives and opportunities for gaming, as well as breaches of standards of conduct between affiliates.
Presently, the MISO intends to leave this structure in place until the first quarter of 2005, when a centralized process for procuring ancillary services is to be implemented. The presently planned delays in providing ultimate control as the ancillary services provider of last resort to the MISO under its tariff, as well as the existence of separate individualized agreements between MISO and the control areas, creates an unacceptable amount of uncertainty. The existence of such a complex, ambiguous scheme reinforces the need for control area consolidation as soon as possible. This protracted delay in bringing the ancillary service markets and reliability-related functions within the MISO’s control will undermine the initial organization of the markets and therefore should be reconsidered. Accordingly EPSA urges the Commission to establish a date certain by which control area consolidation must occur. At a minimum, in light of recent events the Commission should convene a technical conference to consider this critical issue.
B. Market Mitigation and Resource Adequacy
Although EPSA does not support price mitigation as a permanent feature of workably competitive wholesale markets, EPSA has not opposed the inclusion of a “safety net” bid cap in the MISO tariff. However, mitigation should not become a permanent feature of any RTO market. Thus, the Commission should direct the MISO to include a sunset provision relating to all mitigation measures, including the bid cap.
Further, as EPSA has explained in numerous other filings, a resource adequacy program is necessary to complement any market mitigation protocols. A well-designed resource adequacy program is needed to provide the opportunity for generators to recover their investments in a price-capped market. It is imperative that the Commission recognize this fundamental connection among resource adequacy, assurance of infrastructure investment, and the reduction of volatility in spot energy markets. Effective resource adequacy programs can play a critical role by encouraging forward contracting and, thereby, promoting more stable and predictable markets.
While the Commission has acknowledged, in its February 24 Order, the MISO’s assertion that it currently possesses “healthy” reserve margins, the Commission has also emphasized in the SMD NOPR:
Competitive prices over the long run should recover both the fixed and variable costs of efficient generating units and we fear investors may decline to invest in needed generation, transmission, and demand-side projects if they do not see a reasonable expectation of recovering their costs.
For this reason, EPSA believes that the Commission should refrain from imposing mitigation measures in the absence of demonstrable structural market problems, such as defined load pockets or anomalous market prices, and an established resource adequacy program.
This aspect of a properly structured energy market design reflects fundamental economic principles that transcend regional variation: if only short-run marginal costs are recovered, there are no price signals to the marketplace to provide for the development of future resource adequacy or to ensure the economic viability of existing economic generation. Resource adequacy functions as a necessary complement to mitigation of both short and longer-term markets, as evidenced by the implementation of such requirements in PJM, the New York ISO and ISO New England. Mitigation measures in short-term markets distort the price signals needed to retain existing resources or attract investment in new resources. Therefore, a separate resource adequacy market can provide compensation outside the energy and ancillary services markets to create incentives for needed investment.
Furthermore, price mitigation that results in artificially low prices that fail to reflect the costs of capacity, scarcity, opportunity or risk will act as a disincentive for customers to purchase long-term supplies. A properly designed resource planning and acquisition market structure is the most effective means of ensuring that load-serving entities and their customers enjoy the benefits of supply and service at competitively determined prices. Therefore, EPSA encourages the Commission to require the MISO to address the interplay between the two markets as quickly as possible, and carefully craft mitigation rules and incentives that will best serve the objectives contained in the MISO’s market design.
As the Commission noted in its February 24 Order, the MISO’s stakeholder Supply Adequacy Working Group (SWAG), in conjunction with relevant state commissions, is working on supply adequacy guidelines that will balance the needs of both the short- and long-term markets and promote infrastructure development for reliable transmission system operation. The critical challenge in this process is to design a market without mitigation measures that suppress competitive market price signals. In response to the Commission’s direction, the MISO states that it expects to file a “Module E” in May, 2004, addressing resource adequacy. MISO expects the resource adequacy provisions to become effective in October, 2004. As explained above, EPSA regards mitigation and resource adequacy as complementary market design features which should be implemented simultaneously. However, at a minimum the Commission should not permit any delay in the MISO’s proposed timeline. Finally, we urge the Commission to require MISO to add a specific sunset provision eliminating bid caps and other mitigation measures beyond a reasonable initial period.
C. System Support Resources
EPSA offers conditional support for the provisions contained in section 38.2.6 of Module C relating to uneconomic generation units that the MISO may deem necessary to support system reliability, referred to as “System Support Resources” (SSR). However, the MISO added these provisions, intended to “equitably compensate such generation units to encourage these resources to remain as system assets,” late in the drafting process, depriving stakeholders of sufficient time to review them. Accordingly, EPSA, its members and other stakeholders need more details of this last-minute tariff addition, particularly with respect to reimbursement of costs and, and an opportunity to review the template SSR Agreement.
In its transmittal filing, the MISO specifically states that the “SSR will not bid into the Day-Ahead or Real-Time energy markets or set LMP prices” and that “[t]he Transmission Provider shall make every attempt to minimize the use of SSR.” However, this statement is inconsistent with language contained in the TEMT indicating that uneconomic generation units that are not utilized at full capacity for SSR can bid into the real-time energy market and, therefore, can contribute to LMP price determinations. EPSA requests that the Commission reconcile the discrepancy between the Executive Summary in the transmittal filing and the TEMT. After the Commission provides the necessary clarification, EPSA requests an opportunity to comment on the relationship, if any, between SSR and LMP.
EPSA agrees with the MISO’s intention to limit the use of SSR in its energy market construct. Moreover, rather than administrative procedures, we support the approach that relies upon the LMP model, with price signals based upon real-time units that are on line, for replacing uneconomic units with new generating resources that are more efficient and cost effective. Due to the lack of clarity regarding the operation of SSRs, EPSA urges the Commission to provide guidance to the MISO for a more detailed and comprehensive review conducted within the stakeholder consensus process.
D. Reliability Assessment Commitment
The TEMT correctly indicates that reserve requirements and related procedures are critical to well-functioning energy markets, and that the MISO is “the entity ultimately responsible for reliability in the Transmission Provider Region.” Participation in the Day-Ahead (DA) Energy Market will be voluntary, and there is no must-offer requirement for either generation or load to participate in the DA market. However, the MISO proposes to supplement the offers received in the DA market by conducting a Reliability Assessment Commitment (RAC) process in the post-DA time period. Participation in the RAC is also defined as voluntary. It is unclear how this process may work to ensure reliability: if a unit must be committed to the RAC process for reliability purposes, and both DA and RAC are voluntary, how will the MISO ensure that enough units are actually committed?
According to the MISO, the RAC will “only serve as a reliability backstop by committing incremental resources necessary to ensure grid reliability to account for the Midwest ISO forecast of load for the operating day.” As presently conceived, the RAC process would make additional resources available to the MISO beyond those selected for the DA Schedule to satisfy last minute fluctuations in its load forecast. While recognizing the need for some sort of “backstop” to account for varying load forecasts that may arise between the DA and Real-Time (RT) markets, EPSA cautions that the MISO’s over reliance on the RAC process could compromise the markets themselves. Indeed, the proposed market protocols suggest that, rather than a reliability “backstop,” the MISO could use the RAC process as the primary commitment tool.
Clearly, this tariff provision must be carefully scrutinized, particularly with regard to the potential lack of convergence or correlation between the DA and RT price outcomes. Also, equally important is EPSA’s concern that the TEMT lacks provisions to include or account for generation capacity in the RAC process that is committed to an RTO/ISO outside the MISO’s footprint. EPSA urges the Commission to provide guidance on these important issues. Therefore, EPSA urges the Commission to
provide an outline of questions and issues that could serve as a roadmap for the continuation of the stakeholder consensus process.
E. Attachment J—Bid Submission Time Schedule
Competitive power suppliers who intend to participate in the MISO’s DA energy market will require sufficient time to collect and assess information, as well as establish counterparty contacts, necessary to properly formulate bids. Therefore, the change in bid submission times contained in Attachment J (Original Sheet No. 1765) raises serious concerns. Without providing an opportunity for stakeholder discussion, the MISO moved forward the time by which bids are due to 0900 EST from 1100 EST, effectively making the DA market a two day ahead market.
While EPSA understands that the Security Constrained Unit Commitment (SCUC) process requires that bids be submitted as early as operationally possible, the 0900 time will severely hamper bid preparation, which could potentially compromise this aspect of energy market operations. Not only is the 0900 deadline hours earlier than the schedule submission time in other markets and for other transmission providers, it is also out of sync with the gas nomination deadline, which is 1030 EST. Moreover, it will create significant seams problems with neighboring PJM, which presently has a 1300 bid time, as the two RTO’s move to a common market, resulting in DA bids that will likely be higher due to the lack of accurate gas market data as well as transmission service cost information. EPSA urges the Commission to provide guidance to the MISO, and direct that the time be no earlier than 1300 EST.
F. Confidentiality Procedures
The broad, ill-defined disclosure obligations contained in section 38.7 of Module C provide limited and insufficient confidentiality protections and thus should be rejected. The confidentiality provisions envision access by a potentially wide range of persons and entities, subject to vaguely described confidentiality “obligations.” As EPSA has explained in connection with other proceedings, protecting commercially sensitive information is critical to the integrity and effectiveness of well-functioning competitive markets. The Commission itself has recognized that loosely administered reporting and disclosure schemes would harm not only the sellers providing the information but, ultimately, the competitive market the Commission is striving to promote.
Perhaps most troubling are the disclosure obligations relating to state regulatory commissions set forth in section 38.7.3. Under that section, if a state regulatory commission or their staff, “during the course of an investigation or otherwise,” requests confidential information, the MISO will provide it. Thereupon, the MISO “may” ask the recipients to treat the information as confidential and not make the confidential information available to the public. While the section provides for an opportunity for the affected market participant to respond, this loosely outlined disclosure process begs serious questions, as well as legal issues relating to a state commission’s obligations, irrespective of the TEMT, to disclose data in its possession.
In reviewing and approving proposed confidentiality procedures, the Commission must ensure that, in administering the program, the MISO has sufficiently clear rules for determining whether all requestors, including state commissions, have a legitimate need for commercially sensitive information. This is an especially relevant factor given the Commission’s exclusive jurisdiction over, and direct responsibility for, wholesale power market activities. Beyond this threshold consideration, the procedures should provide not only for notice, but an opportunity for a party whose information is sought to challenge the MISO’s determination whether the requestor has a legitimate need for the information. Further, parties should be able to appeal adverse decisions to FERC before the MISO discloses any information.
Accordingly, EPSA urges the Commission to provide guidelines for determining whether a requestor has a legitimate need for commercially sensitive information, and direct the MISO to work with stakeholders, and the OMS, to more closely examine the confidentiality interests associated with the disclosure of commercially sensitive information. Finally, before implementing any information disclosure program, the MISO should be directed to adopt additional measures necessary to adequately protect market participants, and thereby, the markets themselves.
G. Uninstructed Deviations Penalties
In its TEMT, the MISO proposes to adopt penalties “to dissuade Market Participants from deviating from dispatch schedules set and issued by the Midwest ISO.” As presently proposed, the uninstructed deviation charges would be based upon two tolerance bands within which different penalty levels are set. In the February 24 Order, noting that that the SMD NOPR contemplated such penalties, the Commission stated that it was “not opposed to the Midwest ISO implementing an uninstructed deviation penalty." However, the Commission went on to specifically require the MISO to justify the tolerance levels above which penalties would be charged, the level of the penalties and the manner in which the penalty revenues will be handled. We note that the MISO has not complied with the Commission’s directive to provide such justification in the TEMT and therefore urge the Commission to reject the proposed penalties.
Also, it is unclear whether the Commission considered the existence of “ex post” procedures that, when imposed in conjunction with uninstructed deviation penalties, could result in duplicative, i.e. unjust and unreasonable, penalties. Accordingly, given this lack of justification, and “double-dipping” potential, EPSA urges the Commission to reconsider the need for the uninstructed deviation provision where “ex post” procedures exist.