EXHIBIT 99.317
May 20, 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: ERRATA PAGES
Dear Secretary Boergers:
Enclosed for filing please find errata pages to the transmittal letter
accompanying Amendment No. 8 to the ISO Operating Agreement and Tariff,
including the ISO Protocols, submitted yesterday by the California Independent
System Operator Corporation in the above-referenced proceeding. The enclosed
errata pages, which should be substituted for the respective original pages in
the transmittal letter, correct inadvertent typographical errors. We apologize
for any inconvenience.
Respectfully submitted,
Linda C. Ray
Counsel for the California Independent
System Operator Corporation
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(1), 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 every 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 on every hour of the day to allow the
ISO to meet the NERC control performance criteria (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.
The Honorable David P. Boergers
May 19, 1998
Page 5
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(1) 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.
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
The Honorable David P. Boergers
May 19, 1998
Page 6
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 that 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
load 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 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 each 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(2) 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.
The Honorable David P. Boergers
May 19, 1998
Page 11
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(2) 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.
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 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.(3)
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
to be able to regulate in both the upward and downward directions, the unit may
be 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
The Honorable David P. Boergers
May 19, 1998
Page 15
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(3) 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.
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 $1000. 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 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 or
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
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.
Section 385.2010.
Dated at Washington, D.C., this 20th day of May, 1998.
-----------------------
Harry Dupre
NOTICE SUITABLE FOR PUBLICATION IN THE FEDERAL REGISTER
The California Independent System ) Docket Nos. EC96-19-___
Operator Corporation ) and ER96-1663-___
NOTICE OF FILING
Take notice that on May 20, 1998, the California Independent System Operator
Corporation (ISO) filed errata pages, correcting typographical errors, to the
transmittal letter accompanying Amendment No. 8 to the ISO Tariff, including the
ISO Protocols, which was filed on May 19, 1998 in the above-referenced dockets.
The ISO states that the errata pages have been served upon each person
designated on the official service list compiled by the Secretary in Docket Nos.
EC96-19-003 and ER96-1663-003.