EXHIBIT 99.316
May 19, 1998
THE HONORABLE DAVID P. BOERGERS
ACTING SECRETARY
FEDERAL ENERGY REGULATORY COMMISSION
888 FIRST STREET, N.E.
WASHINGTON, D.C. 20426
RE: CALIFORNIA INDEPENDENT SYSTEM OPERATOR CORPORATION, DOCKET NOS. EC96-19-___
AND ER96-1663-___
AMENDMENT NO. 8 TO THE ISO OPERATING AGREEMENT AND TARIFF, INCLUDING THE
ISO PROTOCOLS
RELATING TO THE ISSUE OF INADEQUATE REGULATION RESERVES BIDS FOR
MAINTAINING ISO CONTROL AREA RELIABILITY
Dear Secretary Boergers:
Pursuant to Section 205 of the Federal Power Act ("FPA"), 16 U.S.C.
ss. 824d, the California Independent System Operator Corporation ("ISO")(1)
respectfully submits for filing an amendment ("Amendment No. 8") to the ISO
Operating Agreement and Tariff, including the ISO Protocols ("ISO Tariff").(2)
Amendment No. 8 involves a proposed interim solution to
- --------
(1) Capitalized terms not otherwise defined herein are defined in the Master
Definitions Supplement, ISO Tariff Appendix A, as filed August 15, 1997.
(2) This numbering system refers to amendments made in 1998, AFTER the
Commission's December 17, 1997 order conditionally accepting the ISO
Tariff, as amended, for filing. The Commission already has acted upon
Amendment Nos. 1-6. See California Independent System Operator Corp., 82
FERCP. 61,312 (1998) (conditionally accepting Amendment No. 1 with
modifications and rejecting Amendment Nos. 2 and 3); California Independent
System Operator Corp., 82 FERCP. 61,327 (1998) (conditionally accepting
Amendment Nos. 4 and 5 without modifications and No. 6 with modification).
The Honorable David P. Boergers
May 19, 1998
Page 2
the significant system reliability concerns and high economic costs resulting
from the lack of adequate Regulation reserves bids in the ISO Ancillary Services
market, which has occurred consistently since the ISO Operations Date. Amendment
No. 8 also proposes certain clarifications regarding the ISO's procedures for
dispatching Generating Units providing Regulation, the need for which became
apparent during the stakeholder discussions that preceded the filing of
Amendment No. 8.
The ISO respectfully requests that the Commission accept Amendment
No. 8 for filing and make it effective as of May 19, 1998. Additionally, because
of the persistent risks to system reliability for which Amendment No. 8 proposes
an immediate interim solution, the ISO respectfully requests that the Commission
take expedited action with respect to Amendment No. 8.
Included with this submittal are:
o Amendment No. 8 (providing only the revised excerpts from the ISO Tariff,
including the ISO Protocols, blacklined to show changes from the ISO's
April 1998 Tariff Posting (ATTACHMENT A); and
- --------
Amendment No. 7, filed March 31, 1998 in Docket Nos. EC96-19-023 and
ER96-1663-024, remains pending before the Commission although the ISO has
acted in accordance with that Amendment since the operations date.
Amendment No. 7 proposes certain changes concerning Congestion Management,
Adjustment Bids, the ISO's Balancing Energy software and Reliability
Must-Run charges.
The Honorable David P. Boergers
May 19, 1998
Page 3
o a notice suitable for publication in the Federal Register (ATTACHMENT B).
I. NOTICES
The following individuals should be placed on the Commission's official
service list for this submittal:
N. Beth Emery Fiona Woolf
Vice President and General Linda C. Ray
Counsel Bridget E.R. Shahan
California Independent System Cameron McKenna LLP
Operator Corporation 2000 Pennsylvania Ave., N.W.
151 Blue Ravine Road Suite 8550
Folsom, California 95630 Washington, D.C. 20006
Tele: 916-351-2334 Tele: 202-466-0060
Fax: 916-351-2350 Fax: 202-466-0077
II. BACKGROUND
In every hour of every day since the ISO Operations Date of March 31,
1998, the ISO has conducted four hour-ahead and four day-ahead auctions for
Ancillary Services. These four services are: Regulation, Spinning Reserves,
Non-Spinning Reserves and Replacement Reserves. Each is a capacity-only market.
Bidders must also include an energy bid with each capacity bid. The Energy Bids
in the Regulation template are used for validation only and the Energy Bids for
Spinning, Non-Spinning and Replacement are added to the Balancing Energy and
Ex-Post Price ("BEEP") stack for use as needed in the real-time balancing Energy
market. The difference in treatment of these Energy Bids is one of the
significant causes of the problem that is the subject of this Amendment.
The Honorable David P. Boergers
May 19, 1998
Page 4
For some time, the ISO has been concerned about the "thinness of
Ancillary Services markets." While these markets had insufficient bids in a
number of hours in early days of operation recently(3), the bids have been
adequate for most of the hours in each day for all but Regulation. In nearly all
of the hours for each operating day, the results of the Ancillary Services
auction have left the ISO with insufficient Regulation, in the range of 60 to
100% deficient. This results in a significant reliability concern for the ISO.
As the Commission is aware Regulation is a significant Ancillary Service that is
essential to the reliability of the grid in Energy hour of operation. Unlike
Spinning Reserve, Non-Spinning Reserve and Replacement Reserve which are usually
only called upon for loss of a generator or a significant under forecasting of
control area load. Regulation is called an Energy hour of the day to allow the
ISO to meet the NERC control performance (CPS1 and CPS2) for reliable control
area operation.
The ISO experienced thin Ancillary Services bids during market
demonstration testing that preceded the ISO Operations Date. Accordingly, the
ISO developed, and has routinely implemented since the ISO Operations Date, a
contingency plan in which shortfalls in Ancillary Services, including
Regulation, are covered by calling on Reliability Must-Run ("RMR") Generating
Units.
- --------
(3) The bids for Spinning Reserve have usually been 0-20% deficient in the
hours of a day, the bids for Non-Spinning Reserves 0-10% deficient, the
bids for Replacement Reserves 0-5% deficient.
The Honorable David P. Boergers
May 19, 1998
Page 5
A. IMPACT OF INSUFFICIENT REGULATION
As noted above, Regulation service is required to balance loads and
generation on a continuous basis in every hour of operation. Without adequate
Regulation, the reliability of the Control Area cannot be assured and the ISO's
ability to satisfy Western Systems Coordinating Council ("WSCC") Minimum
Operating Reliability Criteria ("MORC") and North American Electric Reliability
Council ("NERC") Control Performance Standard ("CPS") will continue to be
threatened.
The WSCC's MORC requires that the ISO satisfy the NERC CPS. The NERC
CPS is the measure against which all control areas are evaluated. A control area
that does not comply with CPS is not adequately controlling its system and
imposing burdens as its neighboring control areas. The NERC CPS is composed of
two measures. The first measure (CPS1) is a statistical measure of Area Control
Error (ACE) variability and its relationship to frequency error. The second
measure (CPS2) is a statistical measure designed to limit unacceptably large net
flows in or out of the Control Area.
The ISO triggers CPS2 violations typically during the morning and
evening load ramps. The Control Area ramp in the heavy morning pull and in the
evening drop-off has typically been between 40 and 70 MW per minute. In addition
the market behavior creates large interchange ramps at least twice each day that
only partially coincide with control area load increases regulating units need
to be able to make sufficient room to allow these schedules to happen as
scheduled by the market. For example: if at 6:00 AM the inbound ramp from
neighboring control areas is 2000 MW and
The Honorable David P. Boergers
May 19, 1998
Page 6
the load increase during the 20 minute ramp from 5:50 to 6:10 may only be 600
MW. The ISO must find 1400 MW of regulating units than can decrease output
quickly (1400 MW in 20 minutes) to make room for the Energy coming in. During
the additional time between 6:10 and 6:50 when the next ramp starts the control
area loop will increase and absorb the remaining 1400 MW of the 6:00 increase.
At 6:50, the process repeats itself as it will each hour until the morning pull
is over. The process reverses itself at night as the load falls between 9:00 PM
and 1:00 AM. To follow these ramps effectively, the ISO must use fast-moving
units (typically hydro) to regulate during the ramps. The RMR Units are,
however, mostly slower-moving fossil units with ramp rates of between 2.5 and 7
MW per minute. These RMR units therefore do not provide sufficient regulation
speed (ramp rate) to allow the ISO to follow the load without incurring
violations of the CPS2 criteria.
The two graphs shown below clearly indicate the problems experienced by
the ISO with respect to the Regulation market. The bottom line on Graph No. 1
indicates the absolute minimum Regulation requirements for the ISO during fairly
smooth hours without heavy load ramps. The top line indicates the preferred
level of Regulation capacity to allow the ISO to fully meet the CPS2 performance
criteria including during heavy ramp hours. The middle line indicates the level
of market bids for Regulation service plus the amount of capacity relied upon
from RMR Generating Units for Regulation.
The Honorable David P. Boergers
May 19, 1998
Page 7
GRAPH 1
THE SUM OF CAPACITY BID BY THE MARKET AND
RMR PURCHASED BY THE ISO CONSISTENTLY FALLS
SHORT OF THE PREFERRED REGULATION REQUIREMENTS
(5-10% FORECASTED LOAD).
[GRAPH]
The Honorable David P. Boergers
May 19, 1998
Page 8
As Graph 1 indicates, on numerous occasions the ISO has come
dangerously close to falling below the absolute minimum capacity requirements
for Regulation. Not surprisingly, without adequate Regulation in fast-moving
units, the ISO has had considerable difficulty meeting CPS2 requirements. For
example, on May 1 the ISO recorded 24 CPS2 violations due primarily to a lack of
regulating capacity. Similarly, on May 4, the ISO recorded 34 CPS2 violations
due predominantly to a lack of Regulation capacity. Of greater concern, however,
is the potential effect on reliability if the ISO continues to incur CPS2
violations during the summer peak. During those periods, CPS2 violations are of
greater concern because the "margin for error" is reduced as load increases and
line loadings put greater stress on the system. It is for that reason that an
immediate, albeit temporary measure must be implemented prior to the summer
months.
Unfortunately, as suggested by Graph No. 2 below, the problems
associated with a lack of regulating capacity are likely to increase in the
future. Graph No. 2 shows that from April 1 through May 14 - i.e., over
virtually the entire period of ISO operations -- the amount of market-bid
regulating capacity has steadily declined. As a result, the ISO has been forced
to rely on a steadily increasing amount of RMR capacity to satisfy its
Regulation requirements. Indeed, because of the consistent shortfall in bids for
Regulation reserves, approximately 75% of all ISO requirements for Regulation
since March 31 have come from RMR Generating Units. In many hours, the ISO has
had to procure 100% of Regulation from RMR Generating Units.
The Honorable David P. Boergers
May 19, 1998
Page 9
GRAPH 2
REGULATION RMR IS ON AN UPWARD TREND WHILE
MARKET-PROVIDED CAPACITY IS TRENDING
DOWNWARD.
[GRAPH]
The Honorable David P. Boergers
May 19, 1998
Page 10
B. RELATIONSHIP BETWEEN THE IMBALANCE ENERGY IN MARKET AND REGULATION
Graph No. 1 clearly indicates that there is a significant difference
between the amount of Regulation capacity bid into the market (plus the RMR
capacity) and the preferred level of regulating capacity. The ISO Imbalance
Energy market is designed to provide a resource to provide or absorb energy to
allow the ISO to follow load between Hourly Schedule changes, make up for load
forecasting errors and make up for loss of generation. The Imbalance Energy
market also is the resource for the ISO to use to attempt to return regulating
units back to their preferred operating point to restore the full upward and
downward regulating range of one unit. There are, however some communication and
timing issues which impede full and timely utilization of the Imbalance Energy
market to perform these functions. The sequence in real time occurs as follows.
In order to instruct (increment or decrement) Generators that submit
Supplemental Energy bids, the ISO will manually instruct by phone each Generator
through its Scheduling Coordinator(4) unless the generator is on AGC. For
example, in order to instruct IOU-owned Generating Units, the ISO must first
call the PX (the Scheduling Coordinator for the IOUs), which then contacts the
respective IOU's control center, which then contacts the Generator.
- --------
4 For a detailed operational timeline that may assist in understanding the
examples set forth herein refer to ISO Scheduling Protocol sections 3, 9
and 11.
The Honorable David P. Boergers
May 19, 1998
Page 11
Completing this chain of communication can take as long as ten to fifteen
minutes. During that time the ISO may see load swings of up to 600 MW. Thus the
ISO cannot rely on the manual instruction of Generating Units in order to
reliably match Generation and Load.
Another feature of the RMR units is that they are scheduled "outside"
the market. The Balanced Day-Ahead Schedules submitted by Scheduling
Coordinators do not include the RMR schedules. Each RMR unit placed on line for
any reason creates the need for the ISO to turn to the Imbalance Energy market
to exercise decremental bids ("decs") to make room for the Energy output of the
RMR unit constrained on line. Thus, the more RMR units constrained on line, the
more the need for decremental Supplemental Energy. This condition of being
"outside" the market will continue until the PX is able to participate in the
Hour-Ahead Market. When this happens, the ISO will require all SCs will be
required to include RMR dispatch in their Hour- Ahead Schedules.
The balanced schedules submitted by Scheduling Coordinators include
Adjustment Bids that the ISO may call to resolve congestion; but the ISO must
exercise those bids in pairs, leaving a Scheduling Coordinator in "balance."
Awarding Ancillary Services bids has no effect on the balance because they are
capacity-only. The only opportunity for the ISO to call on generation without
having to call on a Scheduling Coordinator for an offsetting amount of load is
in real-time for Supplemental Energy.
The Honorable David P. Boergers
May 19, 1998
Page 12
A dec bid, if called, obligates the bidder to back down a unit (or
increase a load). Without adequate dec bids in the BEEP stack, the ISO is even
more dependent on Regulation when generation exceeds load, as it will when RMR
units are injected after the Day-Ahead Schedules are final, since other than dec
bids, Regulation is the only market tool available to the ISO to solve
Overgeneration in real time.(5)
To Illustrate the pressure on the Imbalance Energy market consider the
following example. A 300 MW unit may have the following constraints. Absolute
minimum load may be 40 MW, AGC minimum load may be 70 MW. In order for the unit
too be able to regulate in both the upward and downward directions, the unit
maybe loaded at 150 MW. If such a unit can move under regulation @ 3 MW/min and
the ISO needs 60 MW/min regulation speed then 20 such units would be needed if
each unit were loaded at 150 MW to provide this service then 3000 MW of
decremental bids would be needed to accommodate the Energy output of these
units. This example further illustrates the need to get fast moving hydro units
in the regulation market since they satisfy the need best since they have ramp
rates of up to 50 MW/min.
C. COST IMPLICATIONS OF RMR VS. REGULATION BIDS
- --------
(5) This issue will be mitigated when the California Power Exchange
("PX") is able to accept hour-ahead market bids, because the ISO will
then require the PX to include RMR units that are called in its
hour-ahead schedule. The problem with be further reduced when the PX is
able to submit revised bids after the ISO runs Congestion Management for
the day-ahead market. That will allow the ISO to designate RMR units
after the initial day-ahead schedules are set, but have the units
included in the final day-ahead schedule of the PX - avoiding the need to
displace other energy through decs in real-time.
The Honorable David P. Boergers
May 19, 1998
Page 13
The costs associated with calling on RMR Generating Units for purposes
of addressing Ancillary Services shortfalls are significant. These costs exceed
any capacity bid cap required by the Commission and include such other costs as
reliability payments under the RMR contracts. For example, the average RMR
reliability payment is $60.03/MWh. Ancillary Service Regulation capacity bids
(and payments), by contrast, are capped at $9.55/MW.
Additionally, the ISO can incur additional cost due to the primary
purpose for RMR Generating Units being to solve local area reliability problems
associated with maintaining acceptable voltages and line loadings under
single-contingency outage conditions. The ISO's use of RMR Generating Units to
address Ancillary Service shortfalls involves a Control Area reliability
requirement as opposed to a local area requirement and uses valuable starts and
Energy of RMR Generating Units that could be needed for actual local area
reliability needs at a later time. If the ISO has no choice but to call on the
RMR unit later as well, it must pay a substantial penalty for exceeding the
limits.
D. CAUSES OF LACK OF REGULATION BIDS
The ISO believes that a significant cause of the dearth of Regulation
bids relates to the design of the Regulation market and its interplay with the
other markets - all of which provide opportunities for units - in particular low
energy cost units such as hydro - to make more money selling in anything but
Regulation. Specifically, all of the Ancillary Services bids into
The Honorable David P. Boergers
May 19, 1998
Page 14
the ISO's auctions, including Regulation, must be capable of providing Energy in
real time, but as noted above, the ISO calls on real time balancing Energy,
except energy associated with regulation, in economic order, whether or not it
is Energy associated with an Ancillary Services capacity award. However, all of
the bid Ancillary Services, except for Regulation, are paid for Energy based on
Dispatch instructions at marginal interval prices (i.e., at the highest
10-minute price for incremental Energy and at the lowest 10-minute price for
decremental Energy). This means that an Ancillary Services bidder will always
get paid at or above their bid price for Energy delivered from all other
Ancillary Services. By contrast, Regulation Energy deviations are treated as
uninstructed deviations and settled at the Hourly Ex Post Price.
This approach results from the market design -- Regulation is
considered a "zero-Energy" service. Regulating units are intended to be returned
to their "preferred operating point" by calls on the real time balancing Energy
incremental and decremental bids. This means that while the unit may be moved up
and down, its resulting Energy output over the hour for Regulation is expected
to be a net zero.
In practice, units providing Regulation service produce substantial
amounts of Energy in both upward and downward directions depending on the ramp
and system needs. Therefore, in a particular hour, the Generating Unit's actual
output can differ significantly from its scheduled output (either higher or
lower). These deviations are settled at the Hourly Ex Post Price, representing a
risk to bidders of Regulation reserves.
The Honorable David P. Boergers
May 19, 1998
Page 15
For example, the 300 MW Generating Unit referred to earlier may have a
150 MW Energy schedule and be selected to provide Regulation of 50 MW up and 50
MW down (at a price of $7/MW, for instance, taking into account cost caps) and,
based on ramps and other system needs, could end up generating only 100 MWh for
the hour. This is not at all an unlikely outcome given the significant needs for
decremental Energy as explained earlier. The Scheduling Coordinator would be
paid $700 for the Regulation capacity. If the Hourly Ex Post Price is $20/MWh,
the Scheduling Coordinator would incur an Imbalance Energy charge of $1100. As a
result, it costs the Scheduling Coordinator money to bid the resource into the
ISO's Regulation auction. The potential for such outcomes creates disincentives
for Scheduling Coordinators to bid their Generating Units into the ISO's
Regulation reserve auction.
The capacity bid caps approved by the Commission also diminish
incentives for Market Participants to bid. For example, when the PX Energy
market price is expected to be higher than the approved bid cap, the Scheduling
Coordinator will choose the PX Energy market since the ISO offers no incentives
to bid the resource as Regulation but, instead, creates the possibility of the
Scheduling Coordinator losing money based on the Hourly Ex Post Price. This is
particularly true for Hydro units which have very low fuel cost. These are
exactly the units most needed for regulation yet they are the units must likely
to lose money in the "Decremental" situation in which the ISO now operates. If
Market Participants were allowed to bid Ancillary Services at market prices,
this problem could be
The Honorable David P. Boergers
May 19, 1998
Page 16
mitigated in significant degree. However, this is not expected to occur within
the next several weeks or months. In the meantime, as evidenced by the preceding
explanations, the ISO requires an immediate solution to the problem of not
having a sufficient supply of bid Regulation reserves.
III. THE NATURE OF AMENDMENT NO. 8
A. INTERIM REGULATION ENERGY PAYMENT ADJUSTMENT
Clearly, thought needs to be given to whether there are fundamental
design flaws in the Regulation market. The stakeholders want to be actively
involved in those considerations. Reliability will not, however, wait for that
process to be concluded. The key considerations were (1) the solution involve no
software changes and reasonable manual work-arounds; (2) the solution be roughly
fair; and (3) the solution not create significant gaming opportunities.
Consistent with these principles, the ISO Board approved the proposed
change to the Tariff to provide for an additional Energy payment in connection
with Regulation service. In developing this approach, the ISO undertook
extensive consultation with stakeholders, including the evaluation of three
separate options, each with a number of possible variants, which were discussed
at numerous meeting between ISO staff and stakeholders.
At its meeting on May 11, 1998, the ISO Governing Board, after
consideration of all of the options previously discussed with stakeholders,
chose to institute, on an interim basis, a Regulation Energy Payment
The Honorable David P. Boergers
May 19, 1998
Page 17
Adjustment ("REPA"). The REPA is an equation intended to represent the
additional value of Regulation Energy. It is equal to the energy potentially
available in the Regulation bid (R(UP) plus R(DOWN)) times the greater of
$20/MWh or the Hourly Ex Post Price. The total Energy available (R(UP) +
R(DOWN)) may be adjusted to be only R(UP) or only R(DOWN), a percentage of R(UP)
or R(DOWN) or the sum of R(UP) + R(DOWN) depending on the needs, for each
direction of Regulation Service, of the ISO. The product will be adjusted by a
factor, "C," of between 0 and 1. The figure of $20/MWh approximates the ISO's
average price for Imbalance Energy(6) and represents a floor on the price of
Imbalance Energy provided from Regulation resources. This is particularly
important to assuring the ISO's ability to maintain system reliability in
Overgeneration conditions, when the Imbalance Energy price (the Hourly Ex Post
Price), can approach or be zero in some hours.
The factor "C" in the REPA formula is based on the ISO's assessment of
the relative amounts of incremental and decremental activity occurring over the
hour and is intended to be set at the level necessary to attract sufficient
resources into the market. This factor will initially be set at 1 for all hours,
but the ISO proposes that it have the ability to modify the factors relating to
upward and/or downward Regulation both in amount (between 0 and 1) and in its
application to particular times of the day, subject to prior approval of any
such modification by the ISO Governing Board. This will
- --------
(6) This $20/MWh component of the REPA should be contrasted with the $60.03/MWh
average RMR reliability payment. As the ISO's earlier explanations make
clear, if the Commission does not accept the REPA, the ISO will have no
choice but to continue resorting primarily to RMR Generating Units to
assure system reliability.
The Honorable David P. Boergers
May 19, 1998
Page 18
enable the ISO to provide the necessary incentives to ensure that it has the
means available to it to secure system reliability in differing system
conditions. Market Participants will be advised of any such modification by a
notice issued by the ISO's Chief Executive Officer and posted on the ISO's "Home
Page."
The REPA is designed to provide an economic incentive for Generators to
bid into the ISO's Regulation market. The REPA accomplishes this by compensating
Generators for the full range of energy adjustments that they produce when
providing Regulation.(7)
An illustration of how the REPA provides an economic incentive can be
seen by using a simple example. In this example, a Generator bidding at its
Commission-imposed capacity reservation cap of $7.00 per MW is chosen to provide
a 100 MW upward adjustment and a 50 MW downward adjustment to its scheduled
operating level during an hour. For the first 30 minutes of the hour, the
Generator is instructed to move upward by 100 MW. For the second 30 minutes, the
Generator is instructed to move to 50 MW below its scheduled operating level.
Current ISO procedures call for the Generator providing Regulation to
receive payment for the net energy deviation at the average Hourly Ex Post
Price. For example, if the average hourly price were $17/MWh, the
- --------
(7) The ISO notes that REPA will not be paid to a Generating Unit
unless it is available and capable of being controlled and monitored by
the ISO Energy Management System over the full range of its Scheduled
Regulation capacity for the entire Settlement Period at at least the ramp
rates stated in its bid.
The Honorable David P. Boergers
May 19, 1998
Page 19
generator would receive $425 for the net energy of 25 MWh. (The upward
adjustment of 100 MW for 30 minutes minus the 30 minute 50 MW downward
adjustment.) The Generator would also receive a capacity reservation payment of
$1,050, for a total of $1,475.
If the Generator were providing Spinning Reserve instead, the energy
payments would be based upon the 10-minute incremental and decremental energy
prices. If the prices during the hour were $30/MWh for incremental energy and
$5/MWh for decremental energy, the Generator would receive $1,375: $1,500 for
the incremental energy produced (50 MWh at $30/MWh) less $125 paid for the
decremental energy (25 MWh at $5/MWh). The Generator would also receive its
capacity reservation payment of $1,050, for a total of 2,425. By choosing to
provide Spinning Reserve rather than Regulation, the Generator would receive an
additional $950 for the hour under current ISO procedures.
With the REPA, the Generator would receive the capacity payment of
$1,050 and be paid the same $425 for the net energy produced. The ISO would use
the REPA formula to calculate an additional payment of $3,000 for providing a
150 MW range of Regulation, for a total of $4,475. (The amount in this example
is based upon a 100 MW upward increment and a 50 MW decrement, each priced at
$20/MWh. In the REPA formula, the Hourly Ex Post Price would apply if it were
greater than $20/MWh.)
If the unit provided the full decremental capability as may happen in
the present operational circumstances the payments would be 150 X $7 opr
The Honorable David P. Boergers
May 19, 1998
Page 20
1050 for Regulation capacity, 150 X $20 or $3000 for the Energy payment and pay
the ISO back $50 X 17 for the deviation from Schedule. The net payment to the
generator is still $3200 which should incent sufficient participation in the
regulation market.
Even under the higher REPA approach, this is still a substantially less
expensive means to provide Regulation than calling on RMR units, for which the
ISO must make reliability payments of perhaps $60/MWh. Moreover, given the
relatively small amount of Regulation required (5% of load) the ISO does not see
a substantial risk of significant market dislocations even if the ISO determines
based on the market response that the REPA would have been effective with the
constant set initially at a more conservative number. Again, the ISO must err on
the side of reliability to get matters under control, then it will look for ways
to improve cost efficiency further.
The market will be closely monitored to determine the impact of the
REPA payments on the number and price of Regulation bids received. The ISO
believes, however, that the combination of the existing capacity reservation
payment and the proposed REPA should provide sufficient economic incentives to
attract more bids into the ISO Regulation market. Given the consistent and
severe shortfall in Regulation reserves bids that the ISO has experienced since
it commenced operations, the C factor is being set initially at 1, thus
providing the most generous payment possible under
The Honorable David P. Boergers
May 19, 1998
Page 21
the REPA formula. Any future adjustments to the C factor would perforce be
downward, resulting in a lower payment under the REPA formula.(8)
Since the ISO Governing Board will consider and approve any change to
the factor C, there is no risk that the REPA will be applied in an arbitrary or
discriminatory manner. (Indeed, the requirement of Board approval for any
modifications to C was adopted by the Board in response to stakeholder concerns
about allowing changes to be completely at the discretion of the ISO
management.) Moreover, the ability to change C, as it applies to upward and/or
downward Regulation, after due consideration and announcement is an important
tool that provides the ISO with the flexibility both to avoid overcompensation
if a robust Regulation market develops and to ensure in the meantime that
sufficient Regulation resources are available to assure system reliability.(9)
B. CLARIFICATION AMENDMENTS
During the ISO's discussions with stakeholders regarding the Regulation
reserves bids shortfalls, it became evident that the ISO Tariff needs to be
clarified to make it clearer to all market participants that the ISO does not
use Energy bids to determine the dispatch of Generating Units
- --------
8 It bears emphasis that the REPA is an Energy adder payment, not an addition
to the existing capacity payment. Thus, accepting the REPA will not raise
the possibility of exceeding the capacity bid caps previously approved by
the Commission.
9 The ISO notes that the bid evaluation and pricing method currently applied
by the ISO in its Regulation reserves auction, and the settlement at the
Hourly Ex Post Price of real time Energy deviations in response to the
ISO's control of units providing Regulation service, would remain unaltered
by the REPA amendments.
The Honorable David P. Boergers
May 19, 1998
Page 22
providing Regulation, and that Energy from Regulation is paid at the Hour Ex
Post Price as uninstructed Imbalance Energy.
Section 2.5.22.5 of the ISO Tariff and section SP 11.1 of the
Scheduling Protocol state that the ISO's real time merit order stack (as
implemented by the BEEP software) does not include the Energy bids for
Generating Units providing Regulation. Section 2.5.23.2.1 (as amended by section
23) of the ISO Tariff states that only Energy bids included in BEEP are used to
calculate BEEP Interval Ex Post Prices. However, other provisions -- for
example, Section 2.5.22.3.1 of the ISO Tariff, section SBP 5.1.1(j) of the
Schedules and Bids Protocol, section DP 8.7.1(b) of the Dispatch Protocol and
the definition of Instructed Imbalance Energy -- may be read to imply that
Generating Units providing Regulation are dispatched based on the Energy bid
prices. In fact, such units are selected to provide incremental or decremental
Energy by the ISO's Energy Management System and not on the basis of Energy
bids. Notwithstanding this, Energy prices are required to be included in
Scheduling Coordinators' bids into the ISO's Regulation market in order that
they can meet the requirements of the ISO's software for the validation of
Ancillary Services bids.
The necessary clarifying amendments, which unlike the REPA provisions
are not intended to be temporary (except to the extent that Section 23 of the
ISO Tariff is a temporary provision), are included in Amendment No. 8 because
the need for them became known to the ISO during its stakeholder discussions
about the reliability issue that this Amendment principally concerns. The ISO
believes that making the
The Honorable David P. Boergers
May 19, 1998
Page 23
clarifications now will assist generally in encouraging participation in the
ISO's Regulation market.
IV. REQUESTED EFFECTIVE DATE FOR AMENDMENT NO. 8
The ISO respectfully requests that the Commission accept for filing
Tariff Amendment No. 8 and allow it to become effective as of May 19, 1998.
V. REQUEST FOR WAIVER OF THE 60-DAY FILING REQUIREMENT AND EXPEDITED
CONSIDERATION
Pursuant to Section 35.11 of the Commission's regulations,(10) the ISO
respectfully moves for waiver of the 60-day prior notice requirement with
respect to proposed ISO Tariff Amendment No. 8. Additionally, the ISO
respectfully requests that the Commission take expedited action on Amendment No.
8.(11)
Good cause exists for the Commission to grant the ISO a waiver of the
60-day notice requirement. Proposed ISO Tariff Amendment No. 8 is intended to
ensure an adequate supply of Regulation reserves for the ISO's necessary
purposes of maintaining ISO Control Area reliability and to
- --------
(10) 18 C.F.R.ss. 35.11 (1997).
(11) The ISO also respectfully moves for waiver of any other applicable
provision of part 35 of the Commission's regulations pursuant to 18
C.F.R.ss.385.101(e) of the Commission's regulations.
The Honorable David P. Boergers
May 19, 1998
Page 24
adhere to WSCC Minimum Operating Reliability Criteria and NERC Control
Performance Standards. The ISO is mindful of the Director of the Office of
Electric Power Regulation's admonishment regarding waiver of the 60-day notice
period. However, given the critical reliability issues involved, the ISO must
respectfully ask for the Commission to take expedited action on Amendment No. 8.
The ISO has consulted extensively with stakeholders in regard to
Amendment No. 8, and the ISO Governing Board considered various options before
approving the interim REPA. In addition, the ISO will, concurrently with this
filing, take steps to ensure that all parties are quickly informed of Amendment
No. 8 by posting it on the ISO's "Home Page" and faxing to all parties on the
existing service list a notice that the filing may be obtained from the ISO's
"Home Page" if a party wishes to review it in advance of receiving its service
copy.(12)
Wherefore, for the foregoing reasons, the ISO respectfully requests
waiver of the 60-day prior notice requirement for ISO Tariff Amendment No. 8 to
allow it to become effective as of May 19, 1998.
VI. CONCLUSION
Wherefore, for the foregoing reasons, the California Independent System
Operator Corporation respectfully requests that (1) the Commission
- --------
(12) As with the pre-operation amendments, the ISO is filing this amendment in
the existing "WEPEX" dockets, ensuring the broadest possible notice
through the service list in that long-standing docket.
The Honorable David P. Boergers
May 19, 1998
Page 25
accept for filing proposed ISO Tariff Amendment No.8 and allow it to become
effective as of May 19, 1998; and (2) grant such other relief as is requested
herein.
Respectfully submitted,
---------------------------------
Fiona Woolf
Linda C. Ray
Bridget E.R. Shahan
COUNSEL FOR
THE CALIFORNIA INDEPENDENT SYSTEM
OPERATOR CORPORATION
CERTIFICATE OF SERVICE
I hereby certify I have this day served the foregoing submittal upon
each person designated on the Official Service List compiled by the Secretary in
Docket Nos. EC96-19-003 and ER96-1663-003, in accordance with the requirements
of Rule 2010 of the Commission's Rules of Practice and Procedure, 18 C.F.R. ss.
385.2010.
Dated at Washington, D.C., this 19th day of May, 1998.
---------------------
Harry Dupre