UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION

						)
California Independent System		)	Docket No.  ER99-3158-000
	Operator Corporation		)
						)

ANSWER OF THE
CALIFORNIA INDEPENDENT SYSTEM OPERATOR
CORPORATION TO MOTIONS TO INTERVENE AND COMMENTS

	On June 4, 1999, the California Independent System Operator Corporation (“ISO”) filed the “Annual Report on Market Issues and Performance,” prepared by the Market Surveillance Unit of the ISO (“ISO Annual Report” or the “Report”).  Pursuant to Rule 213 of the Commission’s Rules of Practice and Procedure, 18 C.F.R. § 385.213, the ISO hereby submits its Answer to the Motions to Intervene and Comments submitted in response to the June 4th filing.
	The ISO does not oppose any of the requests to intervene, but seeks to respond to some of the comments submitted to clarify the ISO’s position, to rectify any misconceptions, and to promote the development of a complete record.
I.	Introduction
	A.	ISO Annual Report
	As explained in the transmittal letter that accompanied the ISO’s June 4th filing, in its October 30, 1997 order, the Commission accepted the ISO’s proposed market monitoring plan, which included a commitment to have its Market Surveillance Unit prepare and submit annual reports on its activities and the state of competition in the California electricity market to FERC as well as to the California Public Utilities Commission and the California Energy Commission.  The ISO Annual Report filed June 4th was the first such report.  This report discusses and analyzes the ISO’s first year of operation, focusing on those markets for which the ISO is responsible:  the Ancillary Services market, the Real Time Energy market, and the Congestion Management market.  The Report also describes the market challenges faced by the ISO during its first year of operation, the ISO’s efforts to address those challenges, and certain market issues that remain to be resolved.	
	B.	Interventions
	On June 10, 1999, the Commission issued a Notice of Filing.  A notice of intervention was filed by the Public Utilities Commission of the State of California (“CPUC”) and motions to intervene were filed by various parties.  In addition several parties filed motions to intervene and comments. 
II.	Answer to Comments
The intervenor comments on the ISO Annual Report were mostly favorable.  The Cities/MSR, Modesto, TANC, and MWD stated that the Report substantially complies with the October 30 Order and urged the Commission to accept the Report without comment or analysis.  Similarly, SCE commended the Market Surveillance Unit for preparing a thorough and informative report. 
PG&E stated that “the Report provides useful information about the first year of operation of ISO markets . . . ISO has completed a first year of operation with a high degree of success.”  However, PG&E expressed concerns about Ancillary Services (“A/S”) costs, Reliability Must-Run (“RMR”) contracts, and measures of market power as discussed under separate headings below.
NCPA stated that it did not generally disagree with the conclusions of the Report, but believed that until some of the problems identified by the Report were resolved, the ISO would likely continue to have difficulty inducing smaller entities to join.
Only Reliant provided negative comments. Reliant referred to the ISO Annual Report as “largely a rehash of baseless claims.” 
The ISO appreciates and welcomes constructive comments and criticism, and will continue its efforts to improve the efficiency of the ISO markets towards ultimate realization of its motto, “Reliability through Markets.”  In this answer, the ISO will address specific issues raised by the intervenors.
A.	Ancillary Services Markets
In reference to the operation of the A/S markets, PG&E states that A/S costs have been high and must be reduced.  PG&E also challenges the reasonableness of ISO’s goal of containing A/S costs to 10-15% of Energy costs.  PG&E remarks that “the Report provides no analysis showing that 10 to 15 percent is a reasonable goal for A/S costs. . . .  ISO must have adequate and balanced incentives in its management structure and procedures to seek to minimize the costs of ISO operation and Energy and A/S procurement.” 
The ISO agrees with PG&E that it is necessary to develop a baseline for a “reasonable” level of A/S costs in a long-term competitive framework.  At this time, however, very limited data or studies are available upon which the “reasonableness” of A/S costs in the ISO’s markets can be directly compared.  As noted in the ISO Annual Report, California is the first market in which A/S have been procured as unbundled products through a competitive market without centralized unit commitment authority.  The self-dispatch decisions allowed generation units is unique to the design of California’s distinct Energy and A/S markets and make it necessary to assess A/S costs as part of an overall market equilibrium.  This greater flexibility which generators have as well as the fact that A/S prices reflect opportunity costs in other markets are important in assessing the level of reasonableness of A/S costs.  As the ISO enters its second year of operation, it is working to develop new analytical approaches for establishing benchmarks against which A/S costs and prices can be compared.  Over the longer term, the performance of the ISO’s markets may be assessed relative to benchmarks produced through market simulations of competitive market conditions, as well as the actual performance of other market designs.    
The discussion of A/S costs and goals in the first ISO Annual Report is not intended to serve as detailed analysis of what would constitute reasonable A/S costs.  The simple cost scenarios presented in the Report are merely intended to provide an indication of the potential range of A/S costs by illustrating the sensitivity of these costs to key factors such as price spikes and payment of market clearing prices to all suppliers.  Due to the many changes in the design and operation of California’s markets during the first year of operation, particularly over the late spring and peak summer months when A/S costs were highest, the ISO believes it would be unwise to extrapolate or develop goals based on more detailed analysis of this limited market data.  Such analysis would require major assumptions about the impact and timing of improvements in market design and efficiency, as well as speculation about future market conditions.
The goal of limiting A/S costs to 10 to 15 percent of total Energy costs was adopted as a performance goal by the ISO Board and management in early 1999 as one of a variety of measurable indicators that could be used to assess the ISO’s performance over time.  Other performance measures focus on reliability, reliance on market mechanisms, and the challenge of innovating and developing consensus through the stakeholder process.  ISO staff and management must balance these different (and sometimes conflicting) goals.
PG&E notes that it generally supported the ISO’s current set of A/S reforms. PG&E, however, emphasizes the importance of two factors requiring continuing attention:  (1) the ISO’s high (relative to historic levels) demand for Ancillary Services, and (2) “the scarcity of suppliers of A/S, especially during periods of congestion.”  PG&E requests that the FERC encourage the ISO to:
•	Increase A/S supply, especially by “reducing constraints on imports of A/S and facilitating participation of other entities and loads;”

•	Reduce A/S demand, through “introduction of a load-following service, stronger incentive for participants to match supply and demand, or providing for demand responsiveness in the A/S markets;”

•	Facilitate integration of the A/S markets to increase market breadth and encourage efficient arbitrage among markets; and

•	Examine the impacts of congestion and zonal procurement of Ancillary Services.
The ISO agrees and is pursuing a number of approaches similar to those described by PG&E.  The ISO notes that the proposed approaches are often interrelated, and their potential effects cannot be understood in isolation from each other.
1.	Increasing A/S Supply  
As noted in the Report, the ISO has relaxed its limits on the share of Spinning and Non-Spinning Reserve capacity that it will procure from out-of-control-area resources.  When the ISO improved its software allowing it to import A/S starting August 6, 1998, the ISO limited imports of Spinning Reserves to 25% of the total Spinning Reserve requirement, and imports of Spinning and Non-Spinning Reserves to 25% of the total requirement for Spinning and Non-Spinning Reserves.  The limit on import of Spinning and Non-Spinning Reserves was necessary due to limitations to call upon resources outside of the ISO Control Area on 10 minute intervals during the hour.  Based on agreements with some of the neighboring control areas to coordinate intra-hour 10-minute schedule changes, this limit now has been increased to 50%.  The higher limit has been reached in 33 hours (less than 3% of the time) since June 1, 1999.  During the same period (between June 1 and July 20, 1999), imports have exceeded the old 25% ceiling during 684 hours (57% of the time).  Thus, the increase in the A/S limit has contributed to increased supplies of Spinning and Non-Spinning Reserves in the California market.  
The ISO continues to monitor this situation and to work towards broader participation of import supplies in the California market.  Since currently transmission capacity can be reserved only under Existing Transmission Contracts (“ETCs”), the ISO’s ability to satisfy its reserve requirements over curtailable interties (New Firm Use capacity) remains limited.  This issue is closely related to the existing Congestion Management rules and software. Until the Congestion Management and Ancillary Services markets are integrated, so that capacity can be set aside (at a price) for reserves, some limits on A/S imports will be necessary.
2.	Reduce A/S Demand 
The ISO agrees that a significant element in the relatively high cost of Ancillary Services is its high demand for reserves, particularly for Regulation. This problem is partly related to the inability of the Imbalance Energy market to respond quickly to short-term imbalances.  Much of the 1999 A/S Redesign project addressed this problem.  The software used to automate Imbalance Energy Dispatch Instructions (i.e., the so-called ANALOPE software that provides for electronic communication and confirmation of dispatch instructions), is directed to this problem.  The revisions made in the area of the procurement and settlement of Replacement Reserves, the Effective-Price settlement of uninstructed deviations, the billing of A/S capacity based on metered demand, and the “no-pay” provisions for A/S capacity that is unable to follow dispatch instructions, are all aimed at the improved functioning of the Real Time Imbalance Energy market, which should permit the ISO to purchase less Regulation capacity.  However, even after all these improvements are in place, the ISO expects the amount of Regulation capacity to remain higher than the levels customary in an integrated utility environment or under a centralized unit commitment and dispatch paradigm.  Centralized unit commitment would ensure technical feasibility of forward market schedules, possibly at increased forward market Energy costs, but with reduced A/S costs.  In the California market there are no centralized unit commitment constraints.  Although this can lead to reduced forward market Energy prices, but higher requirements for Ancillary Services due to Real Time schedule deviations, the overall cost of Energy and Ancillary Services to the end consumer under the California market structure could still be lower than the overall cost under a centralized unit commitment and dispatch paradigm.
The ISO is studying whether additional revisions to its market design would significantly contribute to the functioning of the Real Time market to provide load following.  Such redesign elements might provide additional payments for generating capacity that could follow incremental and decremental instructions on a short delay, or might reduce the payments to purchased capacity which was unable to observe such instructions. 
3.	Facilitate Integration of A/S Markets  
A third area where PG&E asks the FERC to encourage the ISO concerns facilitating integration of the A/S markets.  The aim, according to PG&E, would be to increase market breadth and the efficient arbitrage between markets.  The Rational Buyer procedure is an example of the integration among the A/S markets that PG&E recommends.  The Rational Buyer procedure is now in the final stages of software testing, and will soon be placed in service.  The ISO believes that this procedure will significantly increase the degree of competition faced by participants in the ISO’s markets, and will stimulate aggressive bidding based on the opportunity costs of potential suppliers of A/S capacity.  The ISO’s implementation of the Rational Buyer procedure also takes into account the different supplies available in the Day-Ahead and the Hour-Ahead markets. This is designed to increase the thickness of the Hour-Ahead market.  It allows suppliers who are susceptible to significant changes in their supply conditions after the close of the Day-Ahead market, such as those delivering reserves over curtailable transmission, an improved mechanism for risk management.  
4.	Impacts of Congestion Management and Zonal Procurement on the A/S Markets  

Another area that PG&E wants the ISO to examine is the impact of Congestion Management and Zonal Procurement in the A/S Markets.  The ISO agrees that there are important interactions between the Congestion Management and A/S Capacity markets. The full integration of the two markets is a key element of the ISO’s long-term market design.  This redesign, however, involves substantial software changes both for the ISO and for its market participants, and will not be undertaken immediately.  
Short of full market redesign, however, important steps have been taken to improve the interaction of the two markets.  For example, the ISO has moved away from a blind linkage between Inter-Zonal Congestion and zonal A/S procurement.  In the past, such strict linkage had led to occasional inverted zonal prices for Energy and A/S.  The ISO now analyzes the regional distribution of A/S requirements in conjunction with the available supply of transmission, and procures A/S zonally only if the zonal procurement is necessary for reliability reasons.  
B.	
RMR
PG&E emphasizes that the need for RMR contracts and their form must be carefully reviewed.  The ISO is addressing this issue as part of its Local Area Reliability Service (“LARS”) initiative, designed to determine if there are less expensive alternatives to existing RMR generation.
NCPA submitted comments stating that the ISO Annual Report makes no mention of the ISO’s need to expand the pool of ISO participants to address the problems of transmission congestion and concentrated generation ownership.  NCPA cites its unsuccessful efforts to secure a RMR contract with the ISO as an example of the ISO’s failure to expand the pool of participants. While NCPA is correct that the ISO and NCPA have been unable to reach closure on RMR contracts for certain NCPA generating units, NCPA’s point is inapposite.  The designation of NCPA units as RMR will not enhance the ISO’s ability to address transmission congestion through market mechanisms, nor will it decrease the market concentration of generation.  RMR units operate outside the market and are, by definition, out-of-market tools available to the ISO to address local-area reliability problems, Intra-Zonal Congestion, and the ISO’s Ancillary Service requirements. Even without a RMR designation, NCPA can and does participate in the ISO markets and is registered as a Scheduling Coordinator with the ISO. 
The reason the ISO has been unable to reach agreement with NCPA on the RMR contracts for NCPA’s units is unrelated to the concerns raised by NCPA.  Six NCPA units were selected in the ISO’s 1999 LARS solicitation.  The ISO LARS initiative is designed to determine if there are less expensive alternatives to existing RMR generation.  Subsequent to the designation of the NCPA units by the ISO, the ISO and NCPA began active negotiations on RMR contracts for each unit.  During the course of these negotiations, NCPA raised concerns that RMR status for their units may jeopardize their tax-exempt status and financing.  The ISO and NCPA are in the process of attempting to resolve this issue.  In addition, certain issues have been raised with respect to the local participating Transmission Owner’s obligations to pay the cost of NCPA’s RMR generation.  Again, the inability to reach agreement on NCPA’s RMR contracts is wholly unrelated to the concerns raised by NCPA regarding the need to expand the pool of ISO participants to address the problems of transmission congestion and concentrated generation ownership.
Reliant asserted that the Report only mentions in passing  “the ISO’s abuse of RMR units to correct market design flaws. . . .  The purpose of RMR units is to mitigate locational market power, not to compensate for the ISO’s and the PX’s endemic software problems.”  Under the ISO structure, and as reflected in the ISO Tariff, although the primary use of RMR units is for local reliability, they may also be used to compensate for any deficiencies in the A/S supply through the market, or to alleviate Intra-Zonal Congestion where no workably competitive market is available for that purpose.  The ISO also notes that market design flaws and software deficiencies may give rise to the potential exercise of market power in an otherwise workably competitive market.  
C.	Price Caps
PG&E states that ISO should be permitted to implement measures to limit price escalation because of the impact on ISO and PX markets.  SCE states that its primary request is that FERC provide the ISO price cap authority until such time as there is concrete evidence that ISO markets are workably competitive.
The ISO agrees with PG&E and SCE that it is necessary to have a mechanism to limit rapid and extreme increases in prices in the ISO markets, until such time as it is confident that imperfections in market design have been corrected and these markets are workably competitive.  While the ISO fully expects that the A/S market redesign elements to be implemented this summer and the revised RMR contracts that were implemented this past spring will correct significant market design flaws that were identified during the first year of ISO operation, it believes there is a continuing need for the ISO to moderate price volatility until it is able to:  (1) implement pre-dispatch and netting-out of RMR Energy, to ensure that all scheduled Energy is consistent with the fundamental ISO design principle of balanced schedules; and (2) observe the performance of the markets with the summer 1999 redesign elements and the RMR contract reforms in place, and with prices allowed to move above the current $250 price cap levels. 
The ISO plans to file its proposal on item (1) above with the Commission in October 1999.  Regarding item (2), the ISO Board of Governors has decided to modify its prior policy on price caps in light of the fact that the market redesign software will be implemented in August 1999, rather than in May 1999 as was envisioned when the prior policy was adopted.  Specifically, the Board determined that the ISO should maintain price caps at the current $250 level up to the end of September 1999 to allow a prudent period for testing of the new Ancillary Services software.  The Board also resolved to replace the current caps at that time with an adjustable Price Volatility Limit Mechanism (“PVLM”), and directed ISO Management to prepare a detailed PVLM proposal for Board review at its August 1999 meeting.  Finally, the Board authorized ISO Management to request from the Commission an extension of price cap authority to February 15, 2000, instead of the November 15, 1999, termination date that was specified in the Commission’s May 26, 1999, order.  The Board deemed the extension necessary to allow the ISO to review market performance and the October 15, 1999, reports of the ISO Market Surveillance Committee (“MSC”) and the PX Market Monitoring Committee (“MMC”) and, on that basis, develop a subsequent filing to the Commission regarding price cap policy without facing imminent termination of ISO authority.  
D.	Market Power
Regarding the Residual Supply Index (“RSI”), which was introduced as a measure of market power in the ISO Annual Report, PG&E comments: 
RSI is not meaningful as a stand-alone market power screen; it should be used only in conjunction with market shares. . . .  The Annual Report does not provide any analysis to support the suggestion that RSIs above 100% provide useful information about the potential for market power . . . RSI should be computed based on estimates of the potential competing capacity available in the market, not just historical bid quantities, which could understate potential competition.

The ISO agrees that the RSI should be used in conjunction with other indicators, such as each supplier’s share of total bid or available capacity, in assessing market power.  For instance, as noted in PG&E’s comments, it may not be profitable for a firm facing a residual supply less than 100% of demand to withhold supply (or bid very high prices) if the firm’s total potential supply is relatively small.  It should be noted the description and summary results of the RSI presented in the Report were designed to introduce FERC and ISO market participants to the concept of the RSI, and provide an indication of the potential competitiveness of the ISO’s markets based on this measure.  More detailed analysis of market power of individual firms requires a more explicit assessment of the ability to profitably exercise market power over both the short term and longer run.  Standard analysis of market power includes available capacity with costs near the market clearing price, not potential capacity available at any cost. This better reflects an individual firm’s ability to raise prices significantly above competitive levels.
Reliant also comments on market power.  Reliant states: 
the adverse consequences to the market of the abuse of the utilities’ market power is nowhere examined.  Moreover, all three of the incumbent utilities have sought approval from CPUC to implement one or more of the following programs: purchasing power from the PX Block Forward Energy market, entering into bilateral deals for forward Energy, and establishing a load curtailment program. The MSU’s report ignores entirely the additional bidding and procurement flexibility such programs would contribute to enhance the incumbent utilities’ already “significant” market power.

The ISO’s Market Surveillance Unit has attempted, in its Annual Report, to describe both the potential for market power and the actual exercise of market power in a completely objective manner.  The ISO has also continually sought to identify and to advocate measures to reduce the potential for market power and the opportunities for gaming in the ISO’s markets.  As stated in the Report the ISO has been concerned about the potential exercise of market power by the California IOUs.  While the ISO believes that as net buyers of Energy it is to the IOUs’ advantage to bid defensively in the generation market, the ISO is watchful of their behavior in their role as Transmission Providers and to the possible exercise of monopsony power.  In fact, in response to Reliant’s concerns, the ISO organized a special public session with the MSC on June 7, 1999, to discuss the issues of monopsony and demand-side market power in the California markets.  The main conclusions of this special public MSC session were:
•	The California IOUs are far less capable of exercising monopsony power under the deregulated environment than in the past.

•	The Power Exchange has been very effective in establishing a credible reference for Energy prices in California.

•	Divestiture of the majority of IOU generation capacity has eliminated their ability to control Energy prices by under-pricing generation.

•	Since the UDC load must be served, it will have to show up across the Day-Ahead, Hour-Ahead, and Real Time markets. 

These conclusions support the Report’s finding that monopsony market power was not an issue of major concern during the first year of operation.  A fundamental condition of monopsony power is the ability of the buyer to purchase less in order to reduce the price.  In the restructured California market the demand does not have this ability since it must be served in total regardless of which market (Day-Ahead, Hour-Ahead, or Real Time) it shows up in parts. 
The concerns Reliant expresses about specific proposals the IOUs have filed at the CPUC have not been addressed in the Report because they were not material to assessment of the first year of ISO market performance.  Regardless, during the first year of operation, the lack of demand elasticity and the inability of demand to protect itself from prices unrelated to economies of supply and demand have been of special concern to the ISO. The ISO encourages development of demand-side programs to promote demand elasticity and to accelerate the lifting of price caps. The ISO is monitoring the demand-side programs mentioned by Reliant to ensure that they do not violate the ISO Tariff, and do not lead to monopsony power. 
E.	Transmission Access Charge
NCPA states: 
[U]ntil some of the problems identified by the report are resolved, it is likely that the ISO will continue to have difficulty inducing smaller entities to join.  Perhaps the most startling admission in the report is the observation that the current Transmission Access Charge structure provides no market signals for efficient transmission investment. . . . “[g]rid enhancement and expansion are important elements which will help mitigate market power in the future.”  The report is vague as to how those elements will be called into being.

The ISO agrees with NCPA that grid enhancement and expansion are extremely important issues that affect the performance of the restructured California market as well as the reliability of the ISO system.  As a result, the ISO is extremely concerned about the structure of incentives for system expansion and upgrade, and this issue is explicitly addressed in numerous ongoing ISO activities including grid planning, congestion management, new generator interconnection, and grid access charges. 
For example, the ISO is currently engaged in a stakeholder process to revise the methodology for assessing and collecting the transmission access charge (“TAC”), in preparation for filing the revised methodology early in the year 2000 and implementing the revised methodology, upon Commission approval, on April 1, 2000.  Within this process, the ISO and the market participants are looking carefully at the various incentives that should be incorporated in the new TAC structure, including incentives for transmission system investment and for new members to join the ISO. 
F.	The Mission of the ISO and the Market Surveillance Committee
	Reliant also commented on the independence of the MSC.  In particular, Reliant asserts participants have learned two “lessons” during the period covered by the ISO Annual Report:
(1) the Independent System Operator is, in fact, a huge and direct participant in the California electricity markets, procuring over one billion dollars’ worth of energy, ancillary services and local reliability services per year, and (2) the Market Surveillance Committee (“MSC”), which originally was envisioned as an independent assessor of market structure and performance, has evolved into a consultant to the ISO, collaborating with the ISO on both business and regulatory strategies.

	 Reliant mischaracterizes the ISO as a “direct participant” in California’s Energy markets.  The ISO is a non-profit public benefit corporation organized under the laws of the State of California and responsible for the reliable operation of a grid comprising the transmission systems of PG&E, San Diego Gas and Electric Company, and SCE (the “ISO Controlled Grid”).  It has no financial interest in California electricity markets, nor does it own transmission lines or generating plants.  The ISO’s procurement of Ancillary Services and Imbalance Energy is on behalf of others and is strictly governed by its Tariff.  The ISO is not a market participant but rather a market facilitator.  For example, the ISO has a strategic objective of improving market rules to facilitate markets and promote economic efficiency.  This objective, coupled with a mandate to ensure grid reliability and open access transmission service, constitutes the ISO’s Mission.  Accordingly, the ISO is a “market facilitator,” not a “direct participant” as Reliant contends.  Reliant’s argument would mean that no Regional Transmission Organization could ever be independent.  That is clearly wrong.
Regarding Reliant's second comment, the ISO does not “collaborate” with the MSC in developing policy recommendations.  The MSC strictly guards its status as an independent body.  The MSC would serve no purpose, however, if it failed to interact with the ISO.  Thus, consistent with the orders of the Commission, the ISO provides the MSC with information and data, while seeking the MSC’s input on policy decisions. 
The Commission’s October 30 Order accepting the ISO’s proposed market monitoring plan stated that “[t]he ISO and PX Governing Boards would establish committees of independent experts to review information submitted by the compliance divisions and to make recommendations to their respective Governing Boards.”  From this market monitoring plan, the ISO developed its Market Monitoring and Information Protocol (“MMIP”) which is included in the ISO Tariff.  The MMIP addresses establishment of the MSC and its role in relation to the ISO:  
MMIP 5.1  Establishment
There shall be established on or before ISO Operations Date an ISO Market Surveillance Committee (ISO MSC), whose role it shall be to provide independent external expertise on the ISO market monitoring process as described in this Protocol and, in particular, to provide independent expert advice and recommendations to the ISO CEO and Governing Board.

MMIP 6.2  Evaluation of Information
The ISO MSC may, upon request of the Market Surveillance Unit, the ISO CEO or the ISO Governing Board, or on its own volition, evaluate such information or data as may be collected by the Market Surveillance Unit on the basis of the evaluation criteria developed by the Market Surveillance Unit or on such further articulated evaluation criteria developed by the ISO MSC.  In carrying out such evaluations, the ISO MSC may consult the PX’s Compliance Unit and Market Monitoring Committee with respect to any matter relating to such evaluations.

Interaction between the ISO and the MSC is consistent with these provisions regarding market surveillance.  California’s Energy markets are very complex and policy issues pertaining to them are often equally complicated.  In order for the MSC to provide meaningful recommendations and advice, it must have a thorough understanding of the issues.  ISO staff, particularly the ISO Department of Market Analysis, is often in the best position to provide the necessary background and data to allow the MSC to evaluate policy issues.  As the MSC has often publicly stated, however, it welcomes comments from all stakeholders. 
Reliant further claims that the collaborative effort between the ISO and the MSC “is evidenced by, among other things, the MSC’s recent prearranged support of the ISO’s attempts to extend its price cap authority . . . .”  The ISO, however, did not seek the MSC’s support, but requested the MSC’s advice on what is one of the most important policy issues affecting California’s electricity markets.  This action is consistent with the ISO Tariff, MMIP 6.2, which permits the ISO to seek the MSC’s independent and expert advice on policy issues.  Moreover, the MSC’s position on price caps has been public and consistent since August 1998.  That position has supported more restrictive price caps than the ISO management proposed to its board.  To suggest that the ISO has influenced the MSC position is not supported by the facts.  
III.	Conclusion
	The ISO respectfully requests that the Commission accept its Answer to Motions to Intervene and Comments and further requests that the Commission accept the ISO Annual Report.

				Respectfully submitted,

_____________________________	______________________________
N. Beth Emery				Edward Berlin
Vice President and General Counsel	Kenneth G. Jaffe
Roger E. Smith				Mike E. Ward
Senior Regulatory Counsel			Sara C. Weinberg
The California Independent System	Swidler Berlin Shereff Friedman, LLP
Operator Corporation		3000 K Street, NW
151 Blue Ravine Road			Washington, DC  20007-5116
Folsom, CA  95630

Dated July 23, 1999
CERTIFICATE OF SERVICE
	I hereby certify that I have served the foregoing document upon all parties on the official service list compiled by the Secretary in Docket No. ER99-3158-000 in accordance with the requirements of Rule 2010 of the Commission’s Rules of Practice and Procedure (18 C.F.R. § 385.2010).
	Dated at Washington, DC, on this 23rd day of July, 1999.

				______________________________
				Sara C. Weinberg

3045851.3