FERC Filings
Motion of EPSA for Leave to Intervene and Comment on the Midwest Independent System Operator's Open Access Transmission and Energy Markets Tariff Filing
Comments
EPSA believes that the EMT contains the essential components for the successful implementation of competitive markets in the Midwest through the Centralized Dispatch platform. Particularly, the framework proposed in the EMT 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), with some necessary modifications described below, holds tremendous promise. If effectively implemented, this framework would establish 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. As noted in the Executive Summary to the MISO’s July 25, 2003 tariff filing, 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). The Commission reiterated its objection to multiple control areas in its Advisory Order, stating that “we support consolidation of control area operations and have requested an evaluation of progress towards this goal within one year of Day 2 market start-up.”
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.” While the February 24 Order temporarily approved the MISO’s plan to proceed with the centralized
operation of a multi-control area market, the Commission’s subsequent Advisory Order sent a clear message that the allocation of responsibilities between the MISO and the control areas within its footprint must be reexamined and changed. “The Commission is concerned that the Midwest ISO have the ability to perform all of the functions needed to reliably operate a centralized, bid-based dispatch market over its entire footprint…[o]ur concern is deepened by the fact that part of the Midwest ISO region was the setting for the recent power blackout.”
The language the Commission used in the February 24 Order represented a de facto postponement of control area consolidation and the MISO’s ultimate control over all aspects of ancillary services. However, the rationale outlined in the Commission’s October 29, 2003 Advisory Order, and the August 14 blackout and the subsequent investigation, confirm that the control of all essential transmission-related operations and market functions must be brought under centralized, independent authority as soon as possible. Events subsequent to that Order underscore that the operational challenges and potential risks that such a large number of autonomous control areas in a single market region create are no longer acceptable.
As the August 14 Blackout Task Force determined, the “institutional complexities” among entities with reliability-related responsibilities in the Midwest was a contributing factor in the power outage. In the explanatory materials following its third recommendation concerning the need to strengthen the “institutional framework for reliability management”, the Task Force noted that the existence of multiple control areas in some regions was coming under increasing scrutiny. In explaining the reasons why this arrangement is undesirable, the Task Force observed that:
[t]he resulting institutional fragmentation and decentralization of control leads to a higher number of operating contacts and seams, complex coordination requirements, misalignment of control areas with other electrical boundaries and/or operating hierarchies, inconsistent practices and tools, and increased compliance monitoring requirements. These consequences hamper the efficiency and reliability of grid operations.
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.”
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 §38.6.3 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.
The existence of such a complex and fragmented scheme reinforces the need for control area consolidation as soon as possible. EPSA urges the Commission to reject any assumption that the definition and allocation of responsibilities outlined in NERC’s Functional Model is an acceptable end-state alternative to full-fledged consolidation. Whatever obstacles exist to control area consolidation, it appears that the MISO’s game plan would play both sides against the middle, ultimately failing to resolve the fundamental structural configuration problem.
The MISO’s own statements suggest that it is merely shifting from one form of multi-layered complexity to another, and that, in fact, NERC’s Functional Model provides incomplete guidelines for addressing the multiple control area dilemma. “[T]he characteristics of Control Areas in the Midwest ISO vary significantly…[b]ecause of the diverse nature of the Midwest ISO’s Control Areas, however, it is not possible to assign all Balancing Authority responsibilities as defined in the NERC Functional Model to the Control Area Operators. Instead, the proposed separation of functions assigns the Balancing Authority’s functions to the appropriate entity under the Energy Markets Tariff structure.”
As Joseph Gardner’s Direct Testimony indicates, uncertainties persist regarding the eventual centralization and standardization of control area functions. Further, the approach outlined in the EMT raises serious questions about the operational feasibility of the MISO coordinating the activities of numerous control areas that lack consistent, uniform functions and responsibilities in real time. In his Direct Testimony, Ronald McNamara addresses the points, stating that:
[t]he balkanized structure of the current system requires a substantial degree of communication and coordination between the separate control areas and between each control area and the Midwest ISO…[A]ny coordination or communication failure in this highly complex arrangement (with so many entities managing what is, in reality, a single interconnected grid spanning a huge portion of the North American continent) can have extremely serious consequences.
Accordingly, EPSA urges the Commission to direct the MISO to expedite its discussions with control area operators and provide to MISO and the existing control areas specific guidelines on what the Commission considers to be actual “control area consolidation” and establish a date certain by which such control area consolidation must occur.
B. Deficient Operating Reserve Pricing and LMP Calculations
An important issue related to the excessive authority control areas would exercise over the procurement of regulation and operating reserves requires the Commission’s close scrutiny. This problem, exacerbated by the continued existence of multiple control areas, concerns the rules for the submission of offers and calculations of Locational Marginal Pricing (LMP) in the real-time market set forth in the EMT, particularly Sections 40.2.3, 40.2.5 and 40.2.11. In those provisions, the MISO has failed to provide for the submission of prices for operating reserves, as well as the inclusion of the value of operating reserve deployment into LMP calculations during non-shortage conditions.
This omission creates the serious possibility that prices in the Midwest region will not accurately reflect actual power flows, as well as supply and demand between control areas in real-time. Accordingly, EPSA urges the Commission to direct the MISO to modify the relevant tariff sections to provide that either: (1) energy offers are accepted for operating reserves with the results included in real-time LMP calculation; or (2) when operating reserves are deployed, the LMP will automatically be set at the offer cap for that hour. Alternatively, to avoid uneconomic instructions to generators, the Commission should specifically require direct oversight by the market monitor over the command and control decisions made by control area operators deploying reserves.
C. Grandfathered Agreements
The tariff provisions relating to Grandfathered Agreements (GFA) , added following the tariff withdrawal last fall, provide for the separation of transmission service under GFAs from transmission service taken under the OATT for a six-year transition period. The GFA provisions are intended to preserve the rights of parties to those agreements by ensuring that they remain “financially indifferent” to the treatment of their agreements upon implementation of the EMT. Equally important objectives are to avoid negative impacts on the reliable operation of the transmission system, and placing excessive or unfair financial burdens on other Market Participants.
EPSA supports the general purpose and goals of the GFA provisions contained in the EMT, and applauds the efforts made thus far to fashion an equitable solution that properly balances the interests of all parties. However, certain aspects of the proposed approach should be rethought and adjusted in order to achieve these important, and mutually dependent, goals. Of particular concern is the prospect of uplift under Option B which, rather than ensuring that parties to GFAs remain “financially indifferent”, would actually enhance their rights, thereby shifting undue burdens to other parties.
As Hogan explains,
[i]n effect, the financial implications of Option B would create added benefits for both parties to the GFA. For the customer, the full use-it-or-lose-it feature of physical schedules would be eliminated or substantially reduced. Furthermore, the chance of curtailment under TLR rules would be reduced. And for the TO the cost of any redispatch needed to accommodate firm transactions under the GFA would shift to the Midwest ISO (and hence to those who pay the uplift charges).
Clearly, the adverse impact of this arrangement conflicts with the stated intention for the GFA provisions; merchants, as well as other non-GRA stakeholders, will have to pay these uplift charges as MISO has proposed that they be spread equally among all Market Participants. Essentially, this amounts to a socialized cost shifting that will deprive Market Participants of the fair value of their generation services. Here again, Hogan aptly and succinctly describes the problem: “the Option B approach goes beyond simply preserving rights and benefits under the existing GFAs. Option B creates added benefits for the GFA parties and shifts the corresponding costs onto other non-GFA parties in the market.
EPSA further agrees with Hogan’s observation that “[t]he Commission should recognize the critical importance of preserving these [LMP-based] features of the Midwest ISO design and avoid any rules to accommodate the GFAs that would undermine the operation of the market.” While Hogan goes on to state that the adverse impacts of the proposed options for GFAs would be limited to “cost shifting and uplift outcomes” , those impacts could result in actual financial harm to other Market Participants.
Accordingly, every effort must be made to minimize or eliminate this outcome. Ultimately, the best solution will be for all parties to convert their contracts to agreements consistent with the LMP-related tariff provisions. As further explained below in connection with FTR allocations, EPSA believes that all load has to be scheduled under the same rules. However, under the proposed relevant EMT provisions, GFA holders have been given a better deal than their current contracts. Therefore, the MISO should make every effort to incorporate whatever modifications are needed to equalize the opportunities and benefits available to merchant generators. In this regard, a central objective for the MISO and its stakeholders must be the setting of a date certain for a capacity market and removing the must offer for DNR units.
In the meantime, EPSA supports the MISO’s request that the Commission approve its proposed Expedited Dispute Resolution (EDR) process to take effect on
June 7, 2004 to help ensure that all load can provide the MISO with the information necessary to complete the FTR nomination process for the implementation of the Energy Markets on December 1, 2004.
D. Financial Transmission Rights
The ability of all Market Participants to obtain fair and equal access to Financial Transmission Rights (FTR) to manage the risk of congestion charges assumed when scheduling energy transactions in the Day-Ahead Market is an essential component of the EMT. Indeed, the successful interplay of financial and physical market activity is critical to avoid economic distortions and maximizing the consumer benefits associated with competitive power markets. It is therefore important that the Commission direct the MISO to review and improve the initial provisions governing the FTR allocation to better ensure comparable treatment of Network Resources and Point-to-Point (PTP) transmission service and make monthly FTRs available for PTP transmission. Also, EPSA urges the Commission to accelerate the transition to Auction Revenue Rights (ARR) by imposing a deadline for the conversion to an FTR auction paradigm.
As the MISO notes in its Transmittal Letter, the FTR allocation methodology proposed in the EMT reflects an extensive stakeholder effort that culminated in a so-called ‘compromise proposal’ for allocating FTRs among Market Participants. The ‘compromise proposal’ presents “a multi-tiered nomination methodology that allocates FTRs on an annual basis for both peak and non-peak periods for each of the four seasons.” Notwithstanding the stakeholder effort to date, at least one aspect of the proposed FTR allocation methodology is seriously flawed: as described, the allocation process is likely to disadvantage customers of PTP transmission service.
A primary concern is that the ‘compromise proposal’ is based upon annual service for PTP transmission. In states that have adopted retail choice, however, it is possible for load to move on a monthly basis. Accordingly, many alternative suppliers have purchased less expensive monthly PTP service. MISO’s model fails to accommodate these transactions that are load serving in the candidate FTR allocation process, thus leaving retail choice load FTR options to the residual market or monthly auctions.
In place of the proposal in the EMT, while on a close vote, MISO stakeholders have expressed a preference for an alternative known as the “Cinergy Proposal” which, among other features, enhances comparability by allowing for month-to-month transmission service. Another shortcoming of the MISO’s proposed FTR allocation methodology is the length of time Market Participants will be deprived of FTR auctions and related ARRs. EPSA urges the Commission to direct MISO to accelerate the implementation of an FTR auction paradigm as soon as possible. In this regard, EPSA recommends that the MISO be required to provide annual reports to the Commission on progress toward the ARR model based upon historical LMP data and other relevant information.
E. Market Mitigation and Resource Adequacy
Although EPSA does not support price mitigation as a permanent feature of workably competitive wholesale markets, subject to the following qualification, EPSA does not oppose the inclusion of a reasonable “safety net” bid cap in the MISO tariff at this time, so long as an adequate resource adequacy program is being developed and will be implemented by a date certain. EPSA does not believe that mitigation should become a permanent feature of any RTO market: certainly, market mitigation via a bid cap should not exist in any market that does not also employ a viable capacity market. Thus, in the absence of an adequate resource adequacy plan, the Commission should direct the MISO to include a sunset provision relating to all mitigation measures, including the bid cap.
As EPSA has explained in numerous other filings, a resource adequacy program is necessary to complement any market mitigation protocols. Therefore, EPSA’s comments regarding bid caps in the absence of a more fully developed resource adequacy plan are limited to the immediate MISO EMT and only for a limited period of time as described herein. 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 the 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.
As explained in the MISO’s Transmittal Letter, Module E of the EMT contains resource adequacy provisions, largely derived from existing state requirements and Regional Reliability Council standards. These provisions fill a gap in the July 25 filing, which did not include specific resource adequacy provisions. The MISO intends for Module E to serve as an interim resource adequacy plan (Interim Plan), while the MISO and its stakeholders develop a long-term solution to resource adequacy. In the meantime, however, the interplay of the resource adequacy provisions and the market mitigation scheme outlined in Module D is critical.
In this connection, EPSA continues to have serious concerns regarding the imposition of a $1,000 safety-net bid cap. A central objective of an effective resource adequacy program is that it provides an actual payment stream, with rules that level the playing field for all generators. Accordingly, the amount of the bid cap is crucial, as David Patton acknowledges, there is “a direct relationship between a safety-net bid cap and resource adequacy requirements.” Failing to fairly and sufficiently compensate generators who help ensure resource adequacy will deprive the market of the incentives necessary to attract investment in new facilities. To avoid this outcome, at a minimum, the bid cap must properly reflect scarcity prices.
In its October 29 Advisory Order, the Commission evaluated a higher proposed bid cap of $5,000 per MWh, stating that “[t]he safety-net bid cap needs to be evaluated with respect to how it affects mitigation and scarcity pricing…[w]e agree with Dr. McNamara that it is appropriate to set a safety-net bid cap at the ‘all-in’ cost per megawatt of a peaking facility, given that the Midwest ISO has no resource adequacy mechanism in place at this time.” The Commission’s concern about the creation of seams due to lower bid caps in neighboring RTOs did not preclude the MISO’s higher proposed cap, especially “where capacity markets do not provide revenue options as in the East.”
There is, therefore, substantial urgency to moving beyond the Interim Plan and establish a well-functioning deficiency mechanism that properly compensates generators and creates the incentives for needed infrastructure investment. EPSA applauds the ongoing efforts of the OMS and the Supply Adequacy Working Group (SAWG), including their development of a work plan and related guiding principles. EPSA urges the Commission to establish a firm sunset date for the Interim Plan and closely monitor this process to ensure that the MISO meets the August 1, 2005 date for a capacity market in the Midwest region.
F. Attachment J—Bid Submission Time Schedule
As explained in EPSA’s comments on the EMT MISO filed in July, 2003, 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 retention of the 0900 EST bid submission time effectively makes the DA market a two day-ahead market, and raises serious concerns. In its October 29, 2003 Advisory Order, the Commission appreciated this problem, stating that “we encourage the Midwest ISO to move the bidding deadline to1100 EST as soon as possible.” EPSA urges the Commission to closely scrutinize this provision and direct the MISO to provide specific justification for the need to retain the 0900 bid submission time, and a specific timeline for shifting to later in the day.
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 RTOs 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. The importance of the time schedule for bid submissions cannot be overstated. Indeed, the success of the ongoing effort to establish a joint and common market for MISO and PJM could be seriously jeopardized if the MISO fails to correct this problem immediately. Commission guidance and direction on this issue is urgently needed.
G. Confidentiality Procedures
In §38.9 of Module C, the MISO has enhanced the confidentiality protections afforded to commercially sensitive information. However, as explained below, due to the existence of multiple governmental and regulatory entities vying for various market oversight roles, the protection of commercially sensitive information is, and will continue to be, a matter of utmost importance to market participants. While the section now contains some clearer definitions, the confidentiality provisions still lack sufficiently detailed criteria for determining whether a requestor has both the legal right and legitimate interest in the information, thus allowing access by a potentially wide range of persons and entities.
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. In this regard, it appears that the section needs additional provisions to ensure that only those with a legal right and legitimate need for such information are granted access to it. 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.
EPSA is encouraged by the potential of a nondisclosure agreement to clarify and confirm the limited scope of access to commercially sensitive information, as well as the obligations of the signatories to those agreements. EPSA recommends that the Commission direct the MISO to work with its stakeholders and the OMS, to more closely examine the confidentiality interests associated with the disclosure of commercially sensitive information, and the need for access to information based upon the respective roles of the entities. In this connection, it is especially important that the effort to develop a nondisclosure agreement be done through the stakeholder process, and that they play a significant role in drafting terms and conditions that provide sufficient protection for information that bears directly on the success of their commercial activities, and the larger market itself.
Furthermore, the concept of “Authorized Requestor” in the disclosure obligations relating to state regulatory commissions, and the Organization of MISO States (OMS) in particular, set forth in §38.9.4 should be reviewed and tightened. Essentially, that section automatically bestows Authorized Requestor status on state regulatory commissions and their staff based upon a “statutory authority, obligation or duty…in fulfillment of which” it seeks the protected information. The opportunity for a general, self-serving, interpretation and application of the “in fulfillment of” language begs serious questions regarding the necessary distinctions between federal and state roles and activities that must be maintained.
Concerns about potentially overriding state legislation, the possibility that state utility commissions may not be able to deny other third parties access to the information, and their emerging interest in involving themselves in the interstate facets of RTO activities, reinforce the need to more clearly define when states have a legitimate interest in obtaining commercially sensitive information. In 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.
G. Uninstructed Deviations Penalties
In §40.3.4 of its EMT, the MISO explains that its approach to settling deviations from dispatch instructions will be based upon a single Tolerance Band, with penalties assessed for Uninstructed Deviations outside the defined range. In its October 29, 2003, Advisory Order, the Commission found Uninstructed Deviation penalties to be “an acceptable method to buttress the Midwest ISO’s maintenance of system reliability.” However, the Commission further opined that “efficient price signals provided by LMPs should serve as the primary motivator for market participants to strictly adhere to their own dispatch instructions.”
EPSA reiterates its objection to the imposition of these penalties as being unnecessary and overly burdensome. It remains unclear whether the Commission has properly 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. As proposed, the uninstructed penalty will be imposed on customers that over generate or under generate from their assigned schedules in the real-time market. This outcome would result from the MISO LMP calculation engine, operating at intervals of only several seconds, will be adjusting generation assignments to keep generation and load in its footprint in balance.
However, this process fails to properly account for the natural market forces associated with LMP calculations at generator nodes that will impose virtually instant “rewards” or “penalties” for any over or under uninstructed deviations. This unexpected generation at a node (i.e., uninstructed over generation) or, conversely, a generation shortfall at a mode (uninstructed under generation), produces immediate price pressure, and for uninstructed under generation, upward price pressure, which would be reflected in subsequent LMP calculations.
Therefore, the natural market forces of LMP calculations at the mode points of the generators produces almost instant rewards of punishment for any over or under uninstructed deviation from generation assignments every few seconds. In the EMT, MISO fails to provide sufficient justification for imposing additional, duplicative penalties on generation for uninstructed generation. Moreover, the EMT does not follow the Commission’s instruction on this topic which contemplated further refinement of the uninstructed penalty. Rather, the proposed tariff provision merely continues to include the same language and fails to recognize the inevitable “double-dipping” this would subject generation to in the MISO footprint. Additionally, such duplicative penalty structures do not exist in other RTOs utilizing LMP, such as PJM.
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.
H. Load Serving Entity Definition
In EPSA’s view, the EMT defines Load Serving Entity (LSE) in an overly broad manner that could lead to confusion as to the identity of an LSE in certain transactions. "LSE" is now defined very broadly in the tariff as follows:
1.171 Load Serving Entity (LSE): Any entity that has undertaken an obligation to provide electric energy for end-use customers by statute, franchise, regulatory requirement or contract for load located within or attached to the Transmission System. Where a distribution cooperative or a municipal distribution system otherwise covered by the prior sentence is a wholesale customer of a generation and transmission cooperative or a municipal joint action agency, the generation and transmission cooperative, a state or federal agency or municipal joint action agency may act as the Load Serving Entity for such distribution cooperative or municipal distribution system.
The problem with this definition is that, by including “an obligation to provide electric energy for end-use customers by… contract for load,” could be interpreted to mean that a supplier that sells electricity on a wholesale basis to an LSE (for instance, a municipal utility) under a bilateral contract for use by that municipal utility’s end use customers could also be an LSE. The supplier in that case may or may not be a Transmission Customer, but would certainly be a Market Participant; however, load can only have a single LSE.
MISO’s current Business Practice Manual for Energy Markets (April 6, 2004 version) recognizes and clears up this problem by defining an LSE as an entity that has, in addition to meeting the definition above, “tak[en] Transmission Service on behalf of wholesale or retail power customers” i.e., an entity must also be a Transmission Customer to be an LSE. Thus, the Transmission Customer that has undertaken the obligation to serve the end use load, however that obligation arises, is and should be the sole LSE for that load. EPSA urges the Commission to direct MISO to modify the definition of LSE in the tariff to include this crucial element.
I. Non-Tariff Issues
In its Transmittal Letter, the MISO raised certain “non-tariff” issues relating to “matters beyond the rates, terms and conditions of service” contained in the EMT. Of particular concern are the implications of the December 1, 2004, market start up date on the reporting obligations under the Sarbanes-Oxley legislation, the evaluation of implementation metrics and the existence of seams between the MISO and its neighboring entities. While these are legitimate concerns, they must be balanced against the substantial interest of MISO, its stakeholders, and market participants in implementing the Centralized Dispatch platform as soon as possible. Accordingly, the potential of the MISO should not be obstructed by non-tariff issues without a meaningful review and determination that the financial and reliability-related risks of proceeding outweigh the benefits. Presently, the non-tariff issues do not satisfy that test.
Whatever steps may need to be taken to resolve the non-tariff issues, it is clear that further postponements of the market implementation date would be harmful to the MISO, its stakeholders, market participants, investors and consumers. As outlined in MISO’s Transmittal Letter, these issues can be worked out through the stakeholder process, with MISO retaining its independence and remaining the final decision maker. The concern regarding the Sarbanes-Oxley requirements may provide the basis for a brief delay in market implementation only if they are determined to be too costly relative to one month of energy market operation benefits. Before taking such action, however, the MISO should provide such an assessment to the stakeholders as soon as possible so they may discuss it and provide advice to the Board.
EPSA understands that the MISO has hired PA Consulting as its independent readiness advisor, to provide recommendations regarding certain metrics that should be met prior to market implementation. The MISO stakeholders should have an opportunity to discuss how many metrics have to be met to warrant proceeding with the market implementation. The MISO should only delay the market opening if there are significant operational problems, such as the failure of the relevant models to provide the expected results, or that reliability will be impaired.
Finally, EPSA shares the view of other stakeholders, and the Commission, regarding the importance of increasing the efficiencies and reliability benefits of RTOs by resolving seams issues. EPSA has repeatedly observed that identifying operational priorities and imposing definitive timelines to resolve seams issues is an essential dimension of the Commission’s initiative to establish RTOs and well-functioning competitive power markets. Indeed, to ensure a comprehensive approach to all market-related activities, EPSA has welcomed the Commission’s active role in achieving the critical objectives of consistency, uniformity and liquidity for markets within and across geographic and RTO boundaries.
While the Commission should continue to highlight and focus on seams issues as a critical dimension of any market design, having finalized agreements with each and every non-MISO entity need not be a necessary precondition for the MISO’s market implementation from proceeding as requested. In this connection, EPSA concurs with MISO’s position that “it does not view the lack of these agreements as a barrier to begin market operations given the Midwest ISO is currently operating without these types of agreements being filed with the Commission.” In fact, each month the stakeholders are provided an update in the ongoing dialogue by MISO and its neighbors to have such an agreement in place as soon as possible. Finally, as noted above, while not completely addressed, the reliability-related aspects of the existing seams issues are being sufficiently addressed to have allowed NERC to approve the MISO Reliability Plan.