EXHIBIT 99.228
CALIFORNIA INDEPENDENT SYSTEM OPERATOR
COMPREHENSIVE MARKET REDESIGN (CMR)
STAKEHOLDER COMMENTS ON ISO RECOMMENDATIONS FOR
DEFERRED CONGESTION MANAGEMENT DESIGN ELEMENTS AND CMR ISSUES
NAME OF SUBMITTER: Max Bulk
ORGANIZATION: California Power Exchange
PLEASE POST OUR COMMENTS ON THE ISO WEB SITE: [X] Yes [ ] No
This document describes the ISO's recommendations on deferred Congestion
Management Reform issues as well as CMR issues as they will be presented to the
ISO Governing Board for approval on October 26. It also establishes a format for
Stakeholders to submit their comments. For the deferred Congestion Management
issues, the recommendations are presented by bullet number, according to the
document presented o the Board September 7. For the CMR recommendations, the
recommendations are presented by problem area (e.g., Inadequate Transmission
Capacity) and are numbered sequentially. As you review this document, please do
the following:
1. Review each design element and indicate whether you support the
recommended design element by checking the "Support" or "Do Not Support"
box (you can do this by "clicking" your mouse on the appropriate check
box);
2. State any additional comments at the end of each section; and
3. Save the template with the name "CMR Recommendation - Comments from XXX"
Where "XXX" is the name of your organization.
4. E-Mail your saved template to bwoertz@caiso.com by 5:00 p.m. PDT on
Monday, October 23, 2000.
Comprehensive Market Redesign Recommendation page 1 October 20, 2000,
Stakeholder Comments
DEFERRED CMR DESIGN ELEMENTS
REAL TIME DISPATCH
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POLICY ISSUE STAKEHOLDER POSITION
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18. Even though forward Congestion Management will ensure that schedules are [X] Support
feasible, Intra-LPA congestion (i.e., within LPAs) can occur in
real-time due to departures from schedule, load forecast deviations, or [ ] Do Not Support
changes in system conditions. The operator will resolve these problems
outside the optimization program, by dispatching energy from available
bids in the imbalance energy stack or unused adjustment bids at market
power mitigated energy prices.
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ITEM 18: PX SUPPORT OF THIS LINE ITEM IS CONDITIONAL TO THE DEFINITION OF THE
PROPOSED MARKET POWER MITIGATION.
DAY AHEAD AND HOUR AHEAD CONGESTION MANAGEMENT
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POLICY ISSUE STAKEHOLDER POSITION
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25. The congestion iteration of today's Day Ahead market will be retained. [ ] Support
ISO staff will monitor the use of the iteration to evaluate its
effectiveness in providing SCs the opportunity to self-mange congestion. [X] Do Not Support
There will be one iteration for the Ancillary Service procurement.
Management will bring an appropriate SC specific activity rule to the
Board in the future to eliminate the potential of exercise of market
power in the congestion management process. The ISO will provide
analysis on the use of the iteration and its impact of usage charge and
energy cost.
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ITEM 25: ANY ACTIVITY RULES SHOULD APPLY TO ALL SCS. TARGETING AN ACTIVITY RULE
TO A SPECIFIC SC AND ENFORCING IT ONLY ON THAT SC WOULD BE DISCRIMINATORY. ISO
SHOULD NOT TRY TO PLACE THE BURDEN OF MAKING THE ACTIVITY RULE WORK ONLY ON
CERTAIN SCS. IF ISO WERE TO APPLY THE ACTIVITY RULES IN A NONDISCRIMINATORY
MANNER, PX COULD SUPPORT THIS ITEM.
LOCAL RELIABILITY SERVICES AND LOCATIONAL MARKET POWER MITIGATION(1)
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POLICY ISSUE STAKEHOLDER POSITION
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31. The ISO will identify and obtain forward commitments for resources [ ] Support
needed for local reliability primarily through a Local
Reliability Service procurement for each LRA and in some instances for [X] Do Not Support
non-LRA LPAs when temporary system conditions create
opportunities for exercise of locational market power.
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32. The ISO will allow SCs to self-provide LRS, with each SCs LRS [X] Support
requirement defined to be consistent with LRS cost allocation.
The ISO will then conduct its own LRS procurement in the day/hour for [ ] Do Not Support
any additional needs that are not self-provided by the SCs.
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33. LRS procurement will be performed each day in the Day Ahead market with [X] Support
needed resources appearing in the forward schedules with
Adjustment Bids (that are capped to mitigate market power) and dispatch [ ] Do Not Support
as needed using forward Congestion Management. This method, referred to
as "Market Based Method," will send appropriate price signals to
encourage infrastructure investment since the impact of LRS procurement
will generate usage charges on Inter-LPA interfaces.
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34. The ISO will retain a contract option similar to today's RMR condition 2 [X] Support
that can be elected by those resources needed for local reliability that
would not otherwise be viable in the markets. [ ] Do Not Support
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35. The LRS procurement will be determined based on Operating Procedures and [ ] Support
nomograms and forecast of load and system conditions and will be
defined as a quantity of committed capacity called minimum reliability [X] Do Not Support
capacity (MRC for each LRA and in some cases from specific resources).
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(1) Items 36 and 39 (also deferred by the Board on September 7) are not
included here because they were only required with the 2 DA LRS
procurement process in that they describe the charge and cost
allocations specific to that method
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ITEMS 31 AND 35: THE PX DOES NOT SUPPORT THE ISO OBTAINING FORWARD COMMITMENTS
OF RESOURCES FOR LRS. THAT IS PROPERLY THE PROVINCE OF THE MARKET PARTICIPANTS
AND SCs. ISO SHOULD PROVIDE THE INFORMATION AND MARKET TOOLS THAT THE
PARTICIPANTS NEED TO SCHEDULE TO THE ISO'S LRS REQUIREMENTS. THESE INCLUDE
PUBLISHING THE NOMOGRAMS AND POSSIBLY DEFINING AND SELLING FTRs ON THE
NOMOGRAMS. IF INSUFFICIENT LRS IS SCHEDULED TO MEET THE ISO'S FORECAST NEEDS,
ISO SHOULD PURCHASE CAPACITY THAT IT COULD DISPATCH IN REAL-TIME IF NEEDED TO
MEET THE SHORTFALL AS AN ANCILLARY SERVICE. ISO COULD REQUIRE THAT BIDS TO
PROVIDE THE CAPACITY FOR SUCH AN A/S BE SUBJECT TO CAPS TO MITIGATE MARKET
POWER. ALLOWING ISO TO MAKE FORWARD CAPACITY COMMITMENTS AT ANY LOCATION OTHER
THAN LRAS COULD EXTEND ISO'S DISTURBANCE OF THE MARKETS. AGAIN, IF ISO DEFINES
SUCH REQUIREMENTS AND THE SCHEDULES DO NOT MEET THE ISO'S FORECAST NEEDS, ANY
SHORTFALL COULD BE MET BY PURCHASING A/S CAPACITY.
CMR GLOBAL ISSUES
POLICY OBJECTIVES
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POLICY ISSUE STAKEHOLDER POSITION
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1. The specific problems we identify are: (1) Insufficient Transmission [X] Support
Capacity; (2) Inadequate Demand Responsiveness; (3) Inadequate
Generation Supply; (4) Insufficient Forward Contracting; (5) [ ] Do Not Support
Under-scheduling and Schedule Infeasibility; and (6)
Exercise of Market Power (system-wide and locational). We believe that
these problems arise from the following circumstances:
- Insufficient Infrastructure, Pre-dating Restructuring
- Incomplete Restructuring: Retail Competition
- Ambiguous Roles and Responsibilities of Industry Participants,
and
- Ambiguous Market Rules.
- Our solutions seek to change these circumstances.
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2. Many of the considered solutions to the problems identified require [X] Support
changes in the way the CAISO conducts business as well as changes to the
roles, responsibilities, and business practices of other market [ ] Do Not Support
participants. The efficient operation of the California electricity
market depends upon all market participants acting in concert to fix the
problems that have plagued us. The successful implementation of changes
to the CAISO business practices will be necessary but not sufficient to
establish an efficient and robust electricity market.
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INADEQUATE TRANSMISSION CAPACITY
LONG-TERM GRID PLANNING
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POLICY ISSUE STAKEHOLDER POSITION
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1. OBJECTIVE 1 Ensure that the ISO Controlled Grid is expanded and operated [X] Support
in a manner that satisfies the ISO's Grid Planning and Operating
Criteria. [ ] Do Not Support
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2. OBJECTIVE 2 Formulate a proactive role for the ISO in identifying needed [ ] Support
new transmission projects and expanding transmission facilities
in constrained areas of the grid, to ensure a reliable and efficient [X] Do Not Support
regional transmission network that will facilitate generation competition
in California and access to regional energy markets.
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3. The ISO will develop an ISO Controlled Grid-wide transmission expansion [X] Support
plan based on the Annual Transmission Plans that the ISO Tariff
currently requires Participating TOs to develop. The ISO's comprehensive [ ] Do Not Support
plan may include projects proposed and funded by third parties.
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4. The ISO will continue to determine where the ISO Controlled Grid should [X] Support
be expanded, based on reliability considerations, and will direct the
applicable Participating TO to upgrade the system. [ ] Do Not Support
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5. The ISO will incorporate market considerations when developing its [ ] Support
transmission expansion plan. In particular, the ISO will consider
whether the grid is capable of facilitating a competitive energy market [X] Do Not Support
and effectively mitigating market power. That is, the ISO's transmission
expansion plan will address the adequacy of system capacity to satisfy
load and mitigate local market power through a combination of local
generation and transmission transfer capability. The ISO will then
facilitate the construction of projects to correct deficiencies in this
area, subject to economic justification based on net system benefit.
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6. OBJECTIVE 3 Facilitate competitive provision of transmission [X] Support
infrastructure.
[ ] Do Not Support
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7. To facilitate competition in new transmission, the ISO will retain the [X] Support
current ISO Tariff
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POLICY ISSUE STAKEHOLDER POSITION
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provision that allows third-parties to propose, fund and, if possible, [ ] Do Not Support
construct and own transmission in a Participating Transmission Owner's
service area.
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8. In the case of local (Low Voltage) transmission projects, the ISO will [X] Support
provide for competitive solicitations to identify reliable and
cost-effective non-wires alternatives. A competitive solicitation will [ ] Do Not Support
not ordinarily be conducted in the case of regional projects, i.e.,
projects that comprise the backbone of the transmission system and are
necessary to effectively access regional markets and to minimize
congestion that would affect a large proportion of the California market
(in most cases these facilities are High Voltage facilities). In
general, the ISO will explore non-wires alternatives only for local
projects that do not affect regional expansion plans but may, on a
case-by-case basis, explore non-wires alternatives to regional projects.
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9. The ISO will develop an expedited approval process for transmission [X] Support
projects needed to maintain reliability.
[ ] Do Not Support
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10. OBJECTIVE 4 Create a consistent set of ISO Grid Planning and Operating [X] Support
Criteria.
[ ] Do Not Support
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11. The ISO will develop a set of grid-wide Operating Criteria to be applied [X] Support
consistently throughout the ISO Controlled Grid.
[ ] Do Not Support
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12. The ISO will review the ISO Grid Planning and Operating Criteria in [X] Support
order to develop criteria for both planning and operations that
are fully consistent. This means that if the system is planned and built [ ] Do Not Support
in such a way as to meet the ISO Grid Planning Criteria, then the system
would be able to be operated in a manner that consistently meets the
ISO Operating Criteria.
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13. OBJECTIVE 5. Clarify roles and responsibilities in transmission planning [X] Support
and expansion, and enhance coordination among the ISO and state
entities. [ ] Do Not Support
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14. The ISO will work with the California Public Utilities Commission [X] Support
(CPUC), the Office of Ratepayer Advocate (ORA) and the Electricity
Oversight Board (EOB) to: [ ] Do Not Support
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POLICY ISSUE STAKEHOLDER POSITION
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a) Ensure that the ISO's assessments of need, system impacts,
market impacts, system net benefit, and availability of
non-wires alternatives are most useful to these other entities
in fulfilling their respective responsibilities and will
minimize duplication of effort;
b) Facilitate early identification of emerging issues that are not
within the ISO's usual evaluation framework (e.g., environmental
impacts), so that each entity can perform in a timely manner any
additional analyses required to making necessary findings;
c) Formally incorporate ISO analyses into the CPUC decision
process, i.e., through ISO participation in Certificate of
Public Convenience and Necessity (CPCN) proceedings before the
CPUC; and
d) Provide for ongoing coordination on specific projects to monitor
their progress and ensure their proper and timely completion.
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page 7
ITEMS 2, 3, 4, AND 5: THE BROAD NATURE OF THESE POLICY STATEMENTS GIVES THE PX
SOME CONCERNS THAT MAKES IT DIFFICULT TO SUPPORT THEM AS WRITTEN.
ISO WANTS TO ASSUME A ROLE IN DEFINING TRANSMISSION EXPANSION PLANS TO ENSURE
RELIABILITY AND FACILITATE A COMPETITIVE ENERGY MARKET. GENERATION AND
TRANSMISSION CAN BE VIEWED AS FUNGIBLE COMMODITIES IN SOME INSTANCES SO ISO'S
EFFORTS TO FACILITATE A COMPETITIVE ENERGY MARKET MAY CAUSE RISKS THAT INVESTORS
IN NEW GENERATION OWNERS WOULD BE RELUCTANT TO INCUR. FOR EXAMPLE, ADDING
GENERATION FACILITIES IN SAN FRANCISCO OR INCREASING TRANSMISSION CAPACITY INTO
SAN FRANCISCO COULD BOTH HELP WITH RELIABILITY AND MITIGATE MARKET POWER OF
GENERATORS IN SAN FRANCISCO. THE MARKET RISKS FOR BUILDING GENERATION IN SAN
FRANCISCO WOULD BE BORNE BY THE GENERATION OWNER, WHILE THE COST RISKS OF
BUILDING TRANSMISSION MIGHT BE REDUCED IF THE TRANSMISSION UPGRADE WERE
INCORPORATED IN THE PTOS RATE-BASE. A GENERATION OWNER MIGHT INCUR ADDITIONAL
COSTS TO BUILD IN SAN FRANCISCO BECAUSE IT BELIEVES THAT THE MARKET WOULD REWARD
IT WITH A PREMIUM FOR ITS ENERGY. HOWEVER, ISO COULD DECIDE THAT THE
COST/BENEFITS OF A TRANSMISSION PROJECT WOULD SUPPORT BUILDING THE PROJECT,
THEREBY WIPING OUT THE PREMIUM THAT THE GENERATION OWNER WAS COUNTING ON TO MAKE
ITS PROJECT PROFITABLE IF IT HAD TO COMPETE WITH GENERATION OVER A WIDER AREA
THAT DID NOT FACE THE HIGHER COSTS OF BUILDING IN AN URBAN AREA. ISO'S EFFORTS
TO EXPAND TRANSMISSION TO FACILITATE COMPETITION IN THE ENERGY MARKETS COULD
DAMPEN FORCES THAT WOULD INDUCE INVESTMENT IN GENERATION IN SOME AREAS.
ISO MUST ALSO TAKE CARE IN DETERMINING WHAT CONSTITUTES RELIABILITY. CURTAILMENT
OF SOME DEMANDS WHEN TRANSMISSION IS TIGHT COULD BE VIEWED AS THE DIFFERENT
DEMANDS INDICATING THEIR VALUE OF SERVICE AND THE HIGHER VALUED DEMANDS GETTING
THE TRANSMISSION CAPACITY.
INADEQUATE GENERATION SUPPLY
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POLICY ISSUE STAKEHOLDER POSITION
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15. Ensure that each new facility or, if applicable, re-powered generating [X] Support
unit and major load project is able to connect to the grid with minimal
connection costs and minimal connection-cost uncertainty, thereby [ ] Do Not Support
ensuring access to the market and reducing potential barriers to entry.
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16. The New Facilities Connection Policy will apply to all new or re-powered [X] Support
generating units and to all major load projects that connect directly to
the ISO Controlled Grid. The transmission system is generally planned to [ ] Do Not Support
accommodate "normal" load growth and, therefore, it is not necessary or
appropriate to establish connection requirements to accommodate normal
load growth.
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POLICY ISSUE STAKEHOLDER POSITION
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17. The following cost assessments to new facilities are designed to reduce [X] Support
barriers to, and costs of, entry, while still sending appropriate price
signals to facilities that propose to locate in areas where connection [ ] Do Not Support
costs or adverse impacts on reliability are high. A new facility will be
responsible for:
a) Direct connection costs;
b) Mitigating reliability impacts only if its reliability impacts
will not be fully mitigated by upgrades or enhancements that are
already included in the applicable PTO's annual plan; and
c) Mitigating any adverse impact its connection may have on an
interface's transfer capability, if such impact reduces
reliability. Absent a reliability impact that requires
mitigation, the new facility would compete on an equal basis
with other grid users for the use of congested transmission
interfaces.
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18. The ISO will take a proactive role in processing requests to connect to [X] Support
the ISO Controlled Grid. To achieve this objective, the ISO will:
[ ] Do Not Support
a) Require that each new facility or re-powered existing generating
unit seeking connection submit a Connection Application
b) Process each request for connection and determine the cost
responsibility of each New Facility in conjunction with the
appropriate PTO based on the queue position of the Connection
Application.
c) For each proposed connection, perform or direct the appropriate
PTO to perform or have performed a System Impact Study, a
Facility Study, and any other studies the ISO determines to be
reasonably necessary in response to a Connection Application.
d) Develop detailed planning procedures for all connections to the
ISO Controlled Grid.
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19. Given the current tight supply conditions in California, it may be [ ] Support
appropriate in certain
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POLICY ISSUE STAKEHOLDER POSITION
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circumstances to expand the grid to accommodate new entrants without [X] Do Not Support
charging the costs of such expansion specifically to the new entrants.
By increasing participation in the market, the adverse impacts of
scarcity and locational market power may be reduced, so that all
customers served by the ISO system will benefit from greater access to
and increased participation in the market. In these situations the
needed upgrades will be addressed within the ISO's Long-Term Grid
Planning process.
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ITEM 19: CHARGING SOME NEW ENTRANTS THE COST OF GRID EXPANSION WHILE NOT
CHARGING OTHERS SUCH COSTS COULD BE DISCRIMINATORY. ISO HAS NOT PROVIDED ANY
FIRM GUIDELINES THAT IT WILL FOLLOW IN DETERMINING WHEN A NEW ENTRANT WILL FACE
SUCH CHARGES AND WHEN IT WILL NOT. WITHOUT SUCH GUIDELINES, THE PX CANNOT
SUPPORT THIS PROPOSAL.
UNDER-SCHEDULING AND SCHEDULE INFEASIBILITY
UNDER-SCHEDULING
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POLICY ISSUE STAKEHOLDER POSITION
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20. Large Uninstructed Deviation Charge (LUDC). The ISO will implement a [X] Support
charge of $50 per MWh on large uninstructed deviations from forward
schedules, having the following features: [ ] Do Not Support
(a) No charge will apply to real-time deviations within 10 percent
of final day-ahead schedules and within 5 percent of final
hour-ahead schedules, with appropriate adjustments for any ISO
dispatch instructions.
(b) Day-ahead and hour-ahead charges will be calculated separately
and will be additive.
(c) Charges on load deviations and generation deviations will be
calculated separately and will be additive (i.e., no netting of
load deviations against generation deviations).
(d) LUDC will be assessed for each SC based on its total load
deviation and total generation deviation within each zone or
Locational Pricing Area (LPA) (e.g., this allows netting of
opposite generation deviations in a given SC's portfolio within
the same zone).
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POLICY ISSUE STAKEHOLDER POSITION
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21. Real-time Trading Charge (RTC) on Instructed Deviations. The ISO will [X] Support
implement a trading charge on all instructed deviations from forward
schedules, having the following features: [ ] Do Not Support
(a) All instructed deviations will be subject to the charge,
including OOM purchases.
(b) The initial level of this charge will be zero; i.e., the ISO
will implement this tool, and adjust it as needed after
observing the effectiveness of the other mechanisms proposed to
reduce the volume of the real-time market.
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22. Disposition of Revenues from Deviation Charges. Revenues collected under [X] Support
the LUDC and the RTC will be credited against the ISO's Grid Management
Charge. [ ] Do Not Support
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23. Reallocation of Deviation Replacement Reserve Costs. The cost of [X] Support
procuring Replacement Reserve capacity would be allocated as follows:
[ ] Do Not Support
(a) The Replacement Reserve (RR) capacity price will be treated as a
down payment for any energy dispatched out of RR; i.e., each MWh
of energy dispatched out of RR will receive the higher of the RR
capacity price and the applicable real-time market clearing
energy price.
(b) Remaining RR capacity costs after step (a) will be allocated to
SCs based on the amount, adjusting for instructed deviations, by
which their metered supply and metered consumption exceed final
Hour-ahead schedules.
(c) Remaining RR capacity costs after steps (a) and (b) will be
allocated to SCs based on the amount, adjusting for instructed
deviations, by which their metered supply falls short of final
Hour-ahead schedules.
(d) Remaining costs after steps (a)-(c) will be allocated to SCs
based on their metered load.
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SCHEDULE INFEASIBILITY
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POLICY ISSUE STAKEHOLDER POSITION
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24. Rules to Ensure Feasible Inter-Tie Schedules [X] Support
a) The ISO will preclude, in Day-Ahead and Hour-Ahead Congestion [ ] Do Not Support
Management, non-firm inter-tie schedules from creating
transmission capacity for firm inter-tie schedules in the
opposite direction.
b) The ISO will validate all submitted inter-tie energy schedules
to ensure that any schedules on open (out-of-service) inter-ties
are declined.
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EXERCISE OF LOCATIONAL MARKET POWER
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POLICY ISSUE STAKEHOLDER POSITION
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25. Interim Locational Market Power Mitigation. The ISO will implement an [ ] Support
interim mechanism to mitigate the locational market power of NON-RMR
RESOURCES when these resources are needed at specific locations of the [X] Do Not Support
ISO-controlled grid to ensure reliable operation. The mechanism will
have the following features:
(a) The interim mechanism will remain in effect until the ISO
implements Congestion Management Reform.
(b) For a given local reliability need, the mitigation mechanism
will be invoked when the resource must be called out of the
normal merit order dispatch for Imbalance Energy (i.e., when its
actual bid is above the applicable real-time market-clearing
price).
(c) When the resource's bid is mitigated, an alternative bid will be
substituted that is calculated as follows, in order of
preference:
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POLICY ISSUE STAKEHOLDER POSITION
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(1) The resource's incremental operating cost, verifiable
and on file with the ISO;
(2) A weighted average of competitive real-time
market-clearing prices earned by the resource in all
hours over the last 30 days in which the resource was
dispatched in merit order for Imbalance Energy; the
average will be weighted so as to adjust for similar
operating conditions (e.g., day, hour, system load
level).
(3) The incremental operating cost of a similar resource
(i.e., same fuel type and similar size).
(d) If the resource is dispatched at its mitigated bid for a
specific period of time, and during that time the relevant
real-time price increases above the mitigated bid, the resource
will receive the higher of its mitigated bid and the real-time
price for those intervals.
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ITEM 25: THE REQUIREMENT FOR THE RESOURCES TO FILE THEIR INCREMENTAL OPERATING
COSTS WILL IMPOSE REGULATORY COSTS ON THE RESOURCE OWNERS RE VERIFICATION OF
THESE COSTS. THIS SEEMS TO BE A STEP TOWARD COST-BASED RATES RATHER THAN
(MITIGATED) MARKET-BASED RATES. ALSO, THE INCREMENTAL COSTS MAY NOT COVER THE
TOTAL COSTS FACED BY A UNIT. THE INTERIM MEASURES DO NOT SEEM TO OFFER AN OPTION
SIMILAR TO A TYPE-2 RMR CONTRACT THAT SUCH AN OWNER COULD CHOOSE TO ENSURE COST
RECOVERY.
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