Attachment A

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION

Pacific Gas and Electric Company, 
San Diego Gas & Electric Company,	Docket Nos. EC96-19-___
and Southern California Edison Company	and ER96-1663-___

AMENDMENT NO. 4

SUBMITTED ON
March 3, 1998

I.  INTER-SCHEDULING COORDINATOR TRADES
The ISO proposes to change the ISO Tariff, including the Scheduling Protocol and the Schedules and Bids Protocol, to address concerns that have arisen during market simulation testing.  This issue has been discussed with the Scheduling Coordinator User Group (“SCUG”) in a series of meetings and conference calls.  The ISO Governing Board ("Board") was first briefed on the issue at its January 21, 1998 meeting, at which time it delegated to ISO management the authority to file any necessary Tariff amendments to implement a process acceptable to the Scheduling Coordinators (or "SCs" in the following example).
The problem arises because of delays being experienced in the scheduling process.  The ISO scheduling process for the Day-Ahead Market assumes the following:
10:00 a.m.	SC submits Initial Preferred Schedule
10:05 a.m.	ISO closes Preferred Schedule (validated)
11:00 a.m.	ISO posts Suggested Adjusted Schedule
12:00 p.m.	SC submits Revised Preferred Schedule
12:05 p.m.	ISO closes Revised Preferred Schedule (validated)
1:00 p.m.	ISO posts Final Schedule
5:00 p.m.	ISO completes Schedule check outs with WSCC Control Areas.
In other words, the design assumes that Balanced Schedules are submitted without any errors and the system is thus able to validate them almost instantaneously.  The schedule then assumes the ISO will run the Congestion Management software and within an hour, provide, if Congestion exists, suggested revisions to each Scheduling Coordinator. 
Each Scheduling Coordinator has an hour to revise its Schedule and submit a new Balanced Schedule.  Based on those Schedules, a final Congestion Management run is made and Final Schedules posted.  This must be accomplished close to the scheduled times to enable the ISO to perform check-outs with neighboring Control Areas. 
During testing, the time required to complete and post initial Preferred Schedules has been significantly longer than anticipated.  A significant contributor to the delay has been the mismatches between the parties involved in Inter-Scheduling Coordinator Trades.  In other words, for a single buy-sell between Scheduling Coordinators, the ISO has noted on a regular basis that the seller will report a sale of, for example, 100 MW, but the buyer will report a purchase of only 90 MW or the seller will report a sale at 90 MW and the buyer of 100 MW, even though both Scheduling Coordinators have submitted Balanced Schedules.
The ISO must contact both Scheduling Coordinators to resolve the difference before either Scheduling Coordinator's Schedule can be validated.  If the difference is not resolved, both Schedules are rejected.  Because the ISO's software will not allow it to run the market unless there are Schedules representing at least 90% of the Load, and because many Inter-Scheduling Coordinator Trades are with the PX, which currently represents a majority of the Load, mismatches in Inter-Scheduling Coordinator Trades can in some cases literally stop the market.
While the times by which Schedules are validated are improving, they remain sufficiently delayed to raise serious questions as to whether the ISO will be able to accommodate Revised Preferred Schedules.  While suspending the Congestion iteration process would be one way to address the issue as the learning curve improves, the Scheduling Coordinators have expressed strong opposition to that step because of the economic impact to them of not being able to adjust Schedules to avoid Congestion Usage Charges.
With the concurrence of the Scheduling Coordinators, the ISO is proposing to implement a new procedure to resolve these mismatches when the parties themselves are unable to do so.  The ISO anticipates that, as Scheduling Coordinators become more experienced, the need for the ISO to resolve mismatches will diminish.
This procedure is limited to the Day-Ahead Market.  It cannot be implemented in the Hour-Ahead Market due to insufficient time.
For the Day-Ahead Market, once Preferred Schedules are submitted, the ISO will run the validation process.  If an Inter-Scheduling Coordinator Trade does not match, either due to quantity or location errors, the ISO will give the Scheduling Coordinators involved in the trade approximately one half-hour to resolve the discrepancies and submit modified Preferred Schedules.  At the time the ISO notifies them of the mismatch the ISO will confirm to each Scheduling Coordinator who the other Scheduling Coordinator involved in the trade is and the nature of the mismatch.
Only the Scheduling Coordinators involved in the mismatch will be allowed to modify their Preferred Schedules or Revised Schedules.  The only modification permitted will be for the Scheduling Coordinators to match their Inter-Scheduling Coordinator Trade and then balance their individual Preferred Schedules or Revised Schedules.  
After the one half-hour has elapsed and modified Preferred Schedules or Revised Schedules have been submitted, the ISO will re-run the validation.  If one or more Scheduling Coordinators are still not matched, the ISO will implement the following procedure: 
1.	The ISO will determine which Inter-Scheduling Coordinator Trades do not match.  If the only disagreement is over the quantity of the trade, the ISO will adjust one of the Schedules to match the lower of the scheduled quantities for the trade (i.e., if one Scheduling Coordinator (“SC1”) is selling 100 MW to another Scheduling Coordinator (“SC2”) and SC2 is buying 50 MW from SC1, then the trade would be reduced to 50 MW).  However, if the Scheduling Coordinator with the higher Energy quantity has only Inter-Scheduling Coordinator Trades within its Schedule, then the other Scheduling Coordinator’s Schedule will be increased to match the higher Energy quantity traded (i.e., based on the previous example, if SC1 only has Inter-Scheduling Coordinator Trades then SC2’s trade would be increased to 100 MW from 50 MW).
2.	If there is a dispute over whether the Scheduling Coordinators agreed to any trade at all, or a dispute over the Zone at which it was designated to have occurred, the ISO will remove the disputed trade from the Schedules in which it appears.
3.	As a consequence of these adjustments, the Scheduling Coordinators whose Schedules have been adjusted no longer will have a Balanced Schedule.  The ISO will adjust various resources in each such Scheduling Coordinator’s portfolio based on the type of resource in the following priority: Demands, exports, imports, Generation, other Inter-Scheduling Coordinator Trades.  The adjustments will be based on the available Adjustment Bids. 
4.	The ISO will record the Adjustment Bids that were utilized for this purpose to eliminate the possibility of confusion and remove them from consideration in real time procedures such as Intra-Zonal Congestion.
The ISO will consider the continued need for this process as the market develops.  Over time, the ISO expects Scheduling Coordinators will gain sufficient experience in the market to avoid mismatches.  Moreover, based on discussions with the Scheduling Coordinators, the ISO believes that markets will themselves, in the longer term, develop a structure to resolve mismatches.
ISO TARIFF AMENDMENTS
2.2.8.1	Preferred Schedule.  A Preferred Schedule shall be submitted by each Scheduling Coordinator on a daily and/or hourly basis to the ISO.  Scheduling Coordinators may also submit to the ISO Ancillary Services bids in accordance with Section 2.5.10 and, where they elect to self provide Ancillary Services pursuant to Section 2.5.20.1, an Ancillary Service schedule meeting the requirements set forth in Section 2.5.20.6.  The Preferred Schedule shall also include an indication of which resources (Generation or Load) if any may be adjusted by the ISO to eliminate Congestion.  On receipt of the Preferred Schedule in the Day-Ahead scheduling process, the ISO shall notify the Scheduling Coordinator of any specific Reliability Must-Run Units which have not been included in the Preferred Schedule but which the ISO requires to run in the next Trading Day.  The ISO will also notify the Scheduling Coordinator of any Ancillary Services it requires from specific Reliability Must-Run Units under their Reliability Must-Run Contracts in the next Trading Day.  If the ISO identifies mismatches in the scheduled quantity or location for any Inter-Scheduling Coordinator Trade, it will notify the Scheduling Coordinators concerned and give them until a specified time, which will allow them approximately one half-hour, in which to modify their Schedules to resolve the mismatch before it applies the provisions of Section 2.2.11.3.4.  If the ISO notifies a Scheduling Coordinator that there will be no Congestion on the ISO Controlled Grid and, subject to Section 2.2.11.3.4, the Preferred Schedule shall become that Scheduling Coordinator’s Final Schedule.
2.2.8.2	Suggested Adjusted Schedules.  In the Day-Ahead scheduling process, if the sum of Scheduling Coordinators’ Preferred Schedules would cause Congestion across any Inter-Zonal Interface, the ISO shall issue to the Scheduling Coordinators whose Schedules contribute to the Congestion, an estimate of the Usage Charges if Congestion is not relieved and Suggested Adjusted Schedules that shall reflect adjustments made by the ISO to each Scheduling Coordinator’s Preferred Schedule to eliminate Congestion, based on the initial Adjustment Bids submitted in the Preferred Schedules.  The ISO will include in the Suggested Adjusted Schedules the resolution of any mismatches in Inter-Scheduling Coordinator Trades, as determined by the ISO.
2.2.8.3 	Revised Schedules.  Following receipt of a Suggested Adjusted Schedule, a Scheduling Coordinator may submit to the ISO a Revised Schedule, which shall be a Balanced Schedule, and which shall seek to reduce or eliminate Congestion.  If the ISO identifies mismatches in the scheduled quantity or location for any Inter-Scheduling Coordinator Trade, it will notify the Scheduling Coordinators concerned and give them until a specified time, which will allow them approximately one half-hour, in which to modify their Schedules to resolve the mismatch before it applies the provisions of Section 2.2.11.3.4.
2.2.11.3.4	Adjustments.  Scheduling Coordinators will have the opportunity to resubmit Preferred Schedules and or Revised Schedules upon notice by the ISO if the ISO determines that the quantity or location of the receiving Scheduling Coordinator is not consistent with the quantity or location of the delivering Scheduling Coordinator.  If the Scheduling Coordinators involved in a mismatched Inter-Scheduling Coordinator Trade do not submit adjusted Schedules which resolve any mismatch as to quantities and provided that there is no dispute as to whether the mismatched trade occurred or over its location, the ISO will adjust the Schedule containing the higher quantity to match the scheduled quantity of Energy in the other Schedule, except where the Schedule to be reduced contains only Inter-Scheduling Coordinator Trades, in which case the ISO will adjust the other Schedule to match the Schedule containing the higher quantity.  If there is a dispute between the Scheduling Coordinators as to whether the Inter-Scheduling Coordinator Trade occurred or over its location, the ISO will remove the disputed trade from the Schedules in which it appears.  The ISO will then balance the Schedules which are no longer Balanced Schedules by adjusting resources in the relevant Scheduling Coordinator’s portfolio in accordance with the procedures detailed in the ISO Protocols.
2.2.12.6	ISO Analysis of Preferred Schedules.  On receipt of the Preferred Schedules the ISO will notify Scheduling Coordinators of any specific Reliability Must-Run Units which have not been included in the Preferred Schedule but which the ISO requires to run in the Trading Day.  The ISO will also notify Scheduling Coordinators of any Ancillary Services it requires from specific Reliability Must-Run Units under their Reliability Must-Run Contracts in the Trading Day.  If the ISO identifies mismatches in the scheduled quantity or location for any Inter-Scheduling Coordinator Trade, it will notify the Scheduling Coordinators concerned and give them until a specified time, which will allow them approximately one half-hour, in which to modify their Schedules to resolve the mismatch before it applies the provisions of Section 2.2.11.3.4.  The ISO shall analyze the combined Preferred Schedules submitted by all Scheduling Coordinators to forecast the probability of Congestion being caused by the Preferred Schedules.  If the ISO finds that the Preferred Schedules will not cause Congestion, and subject to Section 2.2.11.3.4, the Preferred Schedules shall become the Final Schedules and the ISO shall notify Scheduling Coordinators accordingly.
2.2.12.7	Issuance of Suggested Adjusted Schedules.  If the ISO finds that the Preferred Schedules would cause Congestion, it shall issue Suggested Adjusted Schedules no later than 11:00 a.m. on the day preceding the Trading Day.  The ISO will include in the Suggested Adjusted Schedules the resolution of any mismatches in Inter-Scheduling Coordinator Trades, as determined by the ISO.
2.2.12.8	Submission of Revised Schedules.  If the ISO has issued Suggested Adjusted Schedules by 12:00 noon on the day preceding the Trading Day, each Scheduling Coordinator may submit a Revised Schedule to the ISO or shall inform the ISO that it does not wish to make any change to its previously submitted Preferred Schedule.  If the ISO identifies mismatches in the scheduled quantity or location for any Inter-Scheduling Coordinator Trade, it will notify the Scheduling Coordinators concerned and give them until a specified time, which will allow them approximately one half-hour, in which to modify their Schedules to resolve the mismatch before it applies the provisions of Section 2.2.11.3.4.
2.2.12.8.1	Revised Schedules Become Final Day-Ahead Schedules.  If the ISO identifies no Congestion on the ISO Controlled Grid and subject to Section 2.2.11.3.4, the Revised Schedules and any unamended Preferred Schedules shall become Final Day-Ahead Schedules and the ISO shall notify Scheduling Coordinators accordingly.
14.1	Liability for Damages.
Except as provided for in Section 13.3.14, the ISO shall not be liable in damages to any Market Participant for any losses, damages, claims, liability, costs or expenses (including legal expenses) arising from the performance or non-performance of its obligations under this ISO Tariff, including but not limited to any adjustments made by the ISO in Inter-Scheduling Coordinator Trades, except to the extent that they result from negligence or intentional wrongdoing on the part of the ISO.
SCHEDULES AND BIDS PROTOCOL AMENDMENTS
SBP 2.2.2	Stage Two Validation
During stage two validation, Schedules will be checked to determine whether each SC’s aggregate Generation and external imports (adjusted for Transmission Losses) and Inter-Scheduling Coordinator Trades (whether purchases or sales) equals the SC’s aggregate Demand forecast, including external exports.  The SC must take into account the applicable Generation Meter Multipliers (GMMs) as described in the SP.  This validation is performed in accordance with the timing requirement described in the SP.  An SC can also check whether its Schedules will pass the ISO’s stage two validation by manually initiating validation of its Preferred Schedules or Revised Schedules, as described in the SP, at any time prior to the deadline for submission of Preferred Schedules or Revised Schedules (as the case may be).  It is the SC’s responsibility to perform such checks, if desired.  The SC will be notified immediately through WEnet of any validation errors.  For each error detected, an error message will be generated by the ISO in the SC’s notification screen which will specify the nature of the error.  If the ISO detects a mismatch in Inter-Scheduling Coordinator Trades, the ISO will notify both SCs of the mismatch in Energy quantity and/or location.  The SC can then look at the notification messages to review the detailed list of errors, make changes, and resubmit the Schedule if it is still within the timing requirements of the SP.  The SC is also notified of successful validation via WEnet.
SCHEDULING PROTOCOL AMENDMENTS
SP 3.1.1	Types of Balanced Schedules
A Schedule shall be treated as a Balanced Schedule when the SC’s aggregate Generation and external imports (adjusted for Transmission Losses) and Inter-Scheduling Coordinator Trades (whether purchases or sales), equal the SC’s aggregate Demand forecast, including external exports, with respect to all entities for which the SC schedules.  On an interim basis, the ISO may assist SCs in matching Inter-Scheduling Coordinator Trades.
SP 3.1.6	Final Schedules
If the ISO notifies a SC that there will be no Congestion on the ISO Controlled Grid based on the Preferred Schedules submitted by all SCs, the Preferred Schedule shall become that SC’s Final Schedule.  If the ISO has adjusted the SC’s Preferred Schedule to match Inter-Scheduling Coordinator Trades then the adjusted Preferred Schedule shall become that SC’s Final Schedule.  If the ISO notifies a SC that there will be no Congestion on the ISO Controlled Grid based on the Revised Schedules submitted by all SCs, the Revised Schedule shall become that SC’s Final Schedule.  If the ISO has adjusted the SC’s Revised Schedule to match Inter-Scheduling Coordinator Trades then the adjusted Revised Schedule shall become that SC’s Final Schedule.  If there is Congestion based on the Revised Schedules or mismatches in Inter-Scheduling Coordinator Trades, the ISO shall adjust the Revised Schedules and issue Final Schedules.  The SCs will be notified, via WEnet, that their Schedules have become final.  The ISO will also publish a final set of Usage Charges for Energy transfers between Zones, applicable to all SCs.
SP 3.2.6.1	Actions by SCs and the ISO
(e)	the ISO will validate (in accordance with the SBP) all SC submitted Preferred Day-Ahead Schedules for Energy and Adjustment Bids and may assist SCs to resolve mismatches in scheduled quantities or locations for Inter-Scheduling Coordinator Trades in accordance with the procedure described in SP 3.2.6.4;
SP 3.2.6.3	Invalidation
Invalidation of the submittal for any Settlement Period results in rejection of the submittal for all Settlement Periods of the relevant Trading Day.  During the initial operations of the ISO, the ISO may assist SCs to resolve mismatches in the scheduled quantities or locations for Inter-Scheduling Coordinator Trades contained in their Preferred Schedules in accordance with SP 3.2.6.4.  SCs may check at any time prior to 10:00 am whether or not their submittal will pass the ISO’s validation checks at 10:00 am.  It is the responsibility of the SCs to perform such checks since Preferred Day-Ahead Schedules, Adjustment Bids, Schedules of self-provided Ancillary Services and Ancillary Services bids which are invalidated cannot be resubmitted after 10:00 am for the Day-Ahead Market, except that, during the initial period of ISO operations, the ISO will allow resubmission of Preferred Schedules which have mismatches in the scheduled quantities or locations for Inter-Scheduling Coordinator Trades.  The ISO will immediately communicate the results of each SC’s 10:00 am validation to that SC via WEnet.
Add the following new Section:
SP 3.2.6.4	Inter-Scheduling Coordinator Trades - Mismatches
During the initial period of ISO operations, if the ISO detects a mismatch in the scheduled quantities or locations for Inter-Scheduling Coordinator Trades, the ISO will promptly notify both the receiving and sending SCs that a mismatch exists and will specify the time, which will allow them approximately one half-hour, by which they may submit modified Schedules which resolve the mismatch.  If the SCs are unable to resolve the mismatch as to quantities in the allotted time and provided there is no dispute as to whether the trade occurred or over its location, then the ISO may adjust the SCs’ Schedules in accordance with the following procedure:
(a)	The ISO will determine which Schedule contains the higher scheduled quantity of Energy for the Inter-Scheduling Coordinator Trade and will reduce it so that it is equal to the lower scheduled quantity.  However, if the Schedule specifying the higher scheduled quantity of Energy contains only Inter-Scheduling Coordinator Trades, the ISO will increase the Schedule specifying the lower quantity of Energy so that it is equal to the higher scheduled quantity of Energy.
(b)	If there is a dispute between the SCs as to whether the trade occurred or over its location, the ISO will remove the disputed trade from the Schedules in which it appears.
(c)	As a consequence of the adjustments under (a) or (b) above, the SCs whose Schedules have been adjusted will no longer have a Balanced Schedule.  The ISO will adjust their resources based on the following priority: Demands, exports, imports, Generation, and other Inter-Scheduling Coordinator Trades.
(d)	The adjustments to each SC’s portfolio will be based on the Adjustment Bids provided by the SC.
(e)	The ISO will notify each SC whose Schedule has been adjusted as to the adjustment in its Schedule.
Revise the following Sections of the Scheduling Protocol:
SP 3.2.8.1	Actions by SCs and the ISO
(a)	SCs will submit Revised Day-Ahead Schedules to the ISO, in response to the ISO’s Suggested Adjusted Day-Ahead Schedules, in accordance with the SBP;
(b)	SCs will submit, as part of their Revised Day-Ahead Schedules, revised Adjustment Bids (allowing the range of usage to change, but not the prices), if any, to the ISO in accordance with the SBP;
(c)	SCs will submit revised Ancillary Services bids, if any, to the ISO in accordance with the SBP and SP 9;
(d)	SCs will submit their schedules for self-provided Ancillary Services, if any, to the ISO in accordance with the SBP and SP 9;
(e)	the ISO will validate (in accordance with the SBP) all SC submitted Revised Day-Ahead Schedules for Energy and Adjustment Bids and may assist SCs to resolve mismatches in scheduled quantities or locations for Inter-Scheduling Coordinator Trades in accordance with the same procedure described in SP 3.2.8.4;
(f)	the ISO will validate (in accordance with the SBP) all SC submitted schedules for self-provided Ancillary Services and Ancillary Services bids which were part of their Revised Day-Ahead Schedules;
(g)	the ISO will start the second (and final) iteration of the Inter-Zonal Congestion Management process as described in SP 10;
(h)	the ISO will start the second (and final) iteration of the Ancillary Services bid evaluation process as described in SP 9; and
(i)	the ISO will use the SC’s Preferred Day-Ahead Schedule in the event the SC does not submit a Revised Day-Ahead Schedule.  If a SC desires to revise only part of its Preferred Day-Ahead Schedule, those portions of the Revised Day-Ahead Schedule must be submitted, including both the removal of any resources in the Preferred Day-Ahead Schedule which are not to be included in the Revised Day-Ahead Schedule and the addition of any resources that were not included in the Preferred Day-Ahead Schedule but that are to be included in the Revised Day-Ahead Schedule.  A SC’s failure to remove such resources will cause the Revised Schedule to be unbalanced, and rejected as such in the ISO’s validation process.
SP 3.2.8.3	Invalidation
Invalidation of the submittal for any Settlement Period results in rejection of the submittal for all Settlement Periods of the relevant Trading Day.  During the initial operations of the ISO, the ISO may assist SCs to resolve mismatches in the scheduled quantities or locations for Inter-Scheduling Coordinator Trades in accordance with 3.2.8.4.  SCs may check at any time prior to 12:00 noon whether or not their submittal will pass the ISO’s validation checks (which are undertaken at 12:00 noon).  It is the responsibility of the SCs to perform such checks since Revised Day-Ahead Schedules, Adjustment Bids, schedules of self-provided Ancillary Services and Ancillary Services bids which are invalidated cannot be resubmitted after 12:00 noon for the Day-Ahead Market, except that during the initial period of operations, the ISO will allow resubmission of Schedules to resolve mismatches in the scheduled quantities and locations for Inter-Scheduling Coordinator Trades.  The ISO will immediately communicate the results of each SC’s 12:00 noon validation to that SC via WEnet.
Add the following new Section:
SP 3.2.8.4	Inter-Scheduling Coordinator Trades - Mismatches
During the initial period of ISO operations, if the ISO detects a mismatch in the scheduled quantities or locations for Inter-Scheduling Coordinator Trades, the ISO will promptly notify both the receiving and sending SCs that a mismatch exists and will specify the time, which will allow them approximately one half-hour, by which they may submit modified Schedules which resolve the mismatch.  If the SCs are unable to resolve the mismatch as to quantities in the allotted time and provided there is no dispute as to whether the trade occurred or over its location, the ISO may adjust the SCs’ Schedules in accordance with the following procedure:
(a)	The ISO will determine which Schedule contains the higher scheduled quantity of Energy for the Inter-Scheduling Coordinator Trade and will reduce it so that it is equal to the lower scheduled quantity.  However, if the Schedule specifying the higher scheduled quantity of Energy contains only Inter-Scheduling Coordinator Trades, the ISO will increase the Schedule specifying the lower quantity of Energy so that it is equal to the higher scheduled quantity of Energy.
(b)	If there is a dispute between the SCs as to whether the trade occurred or over its location, the ISO will remove the disputed trade from the Schedules in which it appears.
(c)	As a consequence of the adjustments under (a) or (b) above, the SCs whose Schedules have been adjusted will no longer have a Balanced Schedule.  The ISO will adjust their resources based on the following priority: Demands, exports, imports, Generation, and other Inter-Scheduling Coordinator Trades.
(d)	The adjustments to each SC’s portfolio will be based on the Adjustment Bids provided by the SC.
(e)	The ISO will notify each SC whose Schedule has been adjusted as to the adjustment in its Schedule.
Amend the following Section:
SP 3.2.9	By 1:00 pm, Day Ahead
By 1:00 pm on the day ahead of the Trading Day (for example, by 1:00 pm on Tuesday for the Wednesday Trading Day) and for each Settlement Period of that Trading Day:
(a)	the ISO will complete the second iteration, if necessary, of the Inter-Zonal Congestion Management process described in SP 10;
(b)	the ISO will provide, via WEnet, Final Day-Ahead Schedules to all SCs which, depending on the existence of Inter-Zonal Congestion, could be:
i.	the Preferred Day-Ahead Schedules (when no Congestion was found at 11:00 am and no mismatched Inter-Scheduling Coordinator Trades);
ii.	the Revised Day-Ahead Schedules (when no Congestion was found at 1:00 pm and no mismatched Inter-Scheduling Coordinator Trades); 
iii.	modified Revised Day-Ahead Schedules for those SCs which had their Revised Day-Ahead Schedules for Energy modified for Inter-Zonal Congestion or mismatches Inter-Scheduling Coordinator Trades; or
(iv)	modified Preferred Day-Ahead Schedules for those SCs which had their Preferred Schedule for Energy modified for Inter-Scheduling Coordinator Trade mismatches;
(c)	the ISO will publish on WEnet the Day-Ahead Usage Charge rate (in $/MWh of scheduled flow) for Energy transfer between Zones, if any;
(d)	the ISO will provide, via WEnet, as part of the Final Day-Ahead Schedules, schedules for Ancillary Services to the SCs which either:
(i)	submitted Ancillary Services bids and which, as a result, have been selected to supply Ancillary; or
(ii)	submitted schedules to self-provide Ancillary Services and which schedules have been validated by the ISO; and
(e)	the ISO will coordinate with adjacent Control Areas on the net schedules between the ISO Control Area and such other Control Areas.  If the ISO and the operator of an adjacent Control Area have different records with respect to the net schedules, individual SC intertie schedules will be examined.  If the other Control Area’s records are determined to be correct, the ISO will notify the affected SC.  The affected SC is required to correct its schedule in the Hour-Ahead Market.
II.	BUY BACK AND SELL BACK OF ANCILLARY SERVICES
IN THE HOUR-AHEAD MARKET
The ISO’s software (but not the ISO Tariff) would allow Scheduling Coordinators to “buy back” in the Hour-Ahead Market Regulation, Spinning Reserve, Non-Spinning Reserve or Replacement Reserve that the Scheduling Coordinator had sold to the ISO in the Day-Ahead Market.  The price for this “buy back” would be the Hour-Ahead Market Clearing Price for the Ancillary Service concerned.  The ISO wishes to offer Scheduling Coordinators this additional option, which will also add flexibility to the ISO’s Ancillary Services market.  Accordingly the ISO proposes revisions to Section 2.5 of the ISO Tariff and Appendix C to the Settlement and Billing Protocol to enable the payments to be made that reflect this change.  Amendments are required to Section 2.5.10.2 of the ISO Tariff, section 5 of the Schedules and Bids Protocol and section 9 of the Scheduling Protocol to provide for the buy-back procedures to be recognized in the scheduling process.
In addition to the buy-back discussed above, the ISO’s software (but not the ISO Tariff) allows a Scheduling Coordinator to “sell back” in the Hour-Ahead Market Regulation, Spinning Reserve, Non-Spinning Reserve or Replacement Reserve if its obligation for any of these Ancillary Services for which it has not self-provided is reduced in the Hour-Ahead Market as compared with the Day-Ahead Market.  This means that the Scheduling Coordinator can sell back to the ISO in the Hour-Ahead Market any of these Ancillary Services in excess of its non-self-provided obligation in the Hour-Ahead Market (although the Scheduling Coordinator will still be charged by the ISO for any amount owed from the Day-Ahead Market).  This is subject to the important proviso that there are buyers in the Hour-Ahead Market for the excess, i.e., that there are Scheduling Coordinators in the Hour-Ahead Market whose non-self-provided obligation has increased as compared with their obligation in the Day-Ahead Market.  The price for any sell back would be the hourly user rate for the Hour-Ahead Market for the Ancillary Service concerned.
The ISO wishes to be able to offer Scheduling Coordinators this option as well, which will also add flexibility to the ISO’s Ancillary Services Market.  Amendments are required to Section 2.5.21 of the ISO Tariff to provide for this in principle.  In addition, Sections 2.5.20.2 and 2.5.28 of the ISO Tariff and Appendix C to the Settlement and Billing Protocol require amendment to allow the payments to be made that reflect this change.
The ISO is aware that the Commission has limited the ability of certain Scheduling Coordinators to sell Ancillary Services at market-based rates.  Although these “buy-backs” and “sell-backs” will be at market-based rates for all Scheduling Coordinators, the approach would not necessarily violate the limits placed on cost-of-service regulated sellers.  First, the buy-back is a purchase.  A cost-of-service regulated Scheduling Coordinator may be limited in its ability to take advantage of the sell-back option. 
ISO TARIFF AMENDMENTS
Amend sections 2.5.10.2, 2.5.20.2, 2.5.21, 2.5.27, 2.5.28 and 2.5.28.4 as follows:
2.5.10.2	Hour-Ahead Auction.  Bids for the ISO’s Hour-Ahead Regulation, Spinning Reserve, Non-Spinning Reserve and Replacement Reserve service market for each Settlement Period must be received at least two hours prior to the commencement of that Settlement Period.  The bids shall include information for only the relevant Settlement Period.  Failure to provide the information within the stated time frame shall result in the bids being declared invalid by the ISO.  Scheduling Coordinators wishing to buy back in the Hour-Ahead Market Regulation, Spinning Reserve, Non-Spinning Reserve or Replacement Reserve capacity sold to the ISO in the Day-Ahead Market pursuant to Section 2.5.21 must do so by submitting a revised bid in the Hour-Ahead Market for the Ancillary Service and resource concerned.
2.5.20.2	Right to Self Provide.  Each Scheduling Coordinator may choose to self provide all, or a portion, of its Regulation and Reserve obligation in each Zone.  The ISO shall schedule self-provided Ancillary Services, Day-Ahead, and Hour-Ahead, and Dispatch self-provided Ancillary Services in real time.  To the extent that a Scheduling Coordinator self provides, the ISO shall correspondingly reduce the quantity of the Ancillary Services concerned which it procures as described in Sections 2.5.14 to 2.5.17.  As of the ISO Operations Date, Scheduling Coordinators must self provide the Operating Reserve required to cover Interruptible Imports and on-demand obligations.  Where a Scheduling Coordinator’s non-self-provided obligation in the Hour-Ahead Market is less than its non-self-provided obligation in the Day-Ahead Market the Scheduling Coordinator will be deemed to sell back the excess to the ISO in the Hour-Ahead Market pursuant to Section 2.5.21. 
2.5.21	Scheduling of Units to Provide Ancillary Services.  The ISO shall prepare supplier schedules for Ancillary Services (both self-provided and purchased by the ISO) for the Day-Ahead and the Hour-Ahead Markets.  The ISO shall notify each Scheduling Coordinator no later than 1:00 p.m. of the day prior to the Trading Day of their Ancillary Services schedules for the Day-Ahead and no later than one hour prior to the operating hour of their Ancillary Services schedules for the Hour-Ahead.  The ISO will publish ISO Protocols setting forth the information which will be included in these schedules.  Where long-term contracts are involved, the information may be treated as standing information for the duration of the contract. 
Once the ISO has given Scheduling Coordinators notice of the Day-Ahead and Hour-Ahead schedules, these schedules represent binding commitments made in the markets between the ISO and the Scheduling Coordinators concerned.  Any minimum energy input and output associated with Regulation and Spinning Reserve services shall be the responsibility of the Scheduling Coordinator, as the ISO's auction does not compensate the Scheduling Coordinator for the minimum energy output of Generating Units bidding to provide these services.  Accordingly the Scheduling Coordinators shall adjust their schedules to accommodate the minimum outputs required by the Generating Units included on the Schedules. 
Notwithstanding the foregoing:
(a)	a Scheduling Coordinator who has sold Regulation, Spinning Reserve, Non-Spinning Reserve or Replacement Reserve capacity to the ISO in the Day-Ahead Market may buy back that capacity in whole or in part from the ISO in the Hour-Ahead Market at the Zonal Market Clearing Price for the Ancillary Service for the Settlement Period concerned for the Zone in which the Generating Units or other resources on behalf or which the Scheduling Coordinator buys back the capacity, are located.  The ISO will purchase the Ancillary Service concerned from another Scheduling Coordinator in the Hour-Ahead Market in accordance with the provisions of the ISO Tariff. 
(b)	a Scheduling Coordinator whose non-self-provided obligation for Regulation, Spinning Reserve, Non-Spinning Reserve or Replacement Reserve for any Zone reduces between the Day-Ahead and Hour-Ahead Market may sell back to the ISO in the Hour-Ahead Market the amount of such Ancillary Service in whole or in part which is in excess of its non-self-provided obligation in the Hour-Ahead Market.  Provided that the ISO has a market for the sale of the Ancillary Service concerned to other Scheduling Coordinators, the price for such a sale back shall be the hourly user rate for the Ancillary Service for the Settlement Period for the Zone concerned in the Hour-Ahead Market.  If the ISO has no market for the sale of the Ancillary Service concerned to other Scheduling Coordinators, the price for the sale back shall be zero. 
2.5.27	Settlements For Contracted Ancillary Services.
Based on the prices and quantities determined in accordance with this Section, the ISO shall operate a daily Settlement function for Ancillary Services it contracts for with Scheduling Coordinators.
	The ISO shall calculate imbalances between scheduled, instructed and actual quantities of Energy provided based upon Meter Data obtained pursuant to Section 10.  Schedules between Control Areas shall be deemed as being delivered in accordance with Good Utility Practice.  The difference between actual and scheduled interchange shall then be addressed in accordance with the WSCC and NERC inadvertent interchange practices and procedures.  Following this practice, all dynamic schedules for Ancillary Services provided to the ISO by other Control Areas shall be deemed delivered to the ISO.  The difference between the Energy requested by the ISO and that actually delivered by the other Control Area shall then be accounted for and addressed through the WSCC and NERC inadvertent interchange practices and procedures.
	Separate payments shall be calculated for each Settlement Period t for each Generating Unit and Load.  The ISO shall then calculate a total daily payment for each Scheduling Coordinator for all the Generating Units and Load that it represents for each Settlement Period t.
	The settlements for the Hour-Ahead markets shall be calculated by substituting Hour-Ahead prices in the relevant formulae and deducting any amounts due to the ISO from Scheduling Coordinators who buy back in the Hour-Ahead Market Regulation, Spinning Reserve, Non-Spinning Reserve or Replacement Reserve capacity they sold to the ISO in the Day-Ahead Market.
2.5.28	Settlement for User Charges for Ancillary Services.
The ISO shall determine a separate hourly user rate for Regulation, Spinning Reserve, Non-Spinning Reserve and Replacement Reserve for each Settlement Period purchased in the Day-Ahead market, and in the Hour-Ahead Market.  Each rate will be charged to Scheduling Coordinators on a volumetric basis applied to each Scheduling Coordinator’s obligation for the Ancillary Service concerned which it has not self-provided.
	Each Scheduling Coordinator’s obligation for Regulation, Spinning Reserve, Non-Spinning Reserve and Replacement Reserve for each Zone shall be calculated in accordance with Section 2.5.20.1.
	The cost of Voltage Support and Black Start shall be allocated to Scheduling Coordinators as described in Sections 2.5.28.
	Except for Replacement Reserve (as to which see Section 2.5.28.4), quantities and rates for the Hour-Ahead markets shall be calculated by substituting the Hour-Ahead quantities and prices in the relevant formulae (including self-provided quantities of the Ancillary Service.)
except that:
(a)	the user rates for Regulation, Spinning Reserve, Non-Spinning Reserve and Replacement Reserve capacity shall be calculated by dividing the net payments made by the ISO for each service by the obligation for each service which has not been self-provided.  The net payments are the total payments for each service net of sums payable by Scheduling Coordinators who have bought back in the Hour-Ahead Regulation, Spinning Reserve, Non-Spinning Reserve or Replacement Reserve capacity, as the case may be, which they had sold to the ISO in the Day-Ahead Market; and 
(b)	the user charges for each Scheduling Coordinator for Regulation, Spinning Reserve, Non-Spinning Reserve and Replacement Reserve capacity shall be reduced by the amount payable by the ISO to the Scheduling Coordinator for any Regulation, Spinning Reserve, Non-Spinning Reserve or Replacement Reserve obligation, as the case may be, sold back to the ISO by the Scheduling Coordinator in the Hour-Ahead Market.
Separate rates shall be calculated for each Service as follows:
2.5.28.4	Replacement Reserve.  The user rate per unit of purchased Replacement Reserve for each Settlement Period in the Day-Ahead Market and Hour-Ahead Markets for each Zone shall be calculated as shown below.  Dispatched Replacement Reserve capacity charges are recovered by an augmentation to the Imbalance Energy Charge to allocate costs associated with the dispatch of Replacement Reserve to those Scheduling Coordinators who contributed to the Imbalance Energy requiring such dispatch.  The calculation of this augmentation is set forth in Section 11.2.4.1 of this ISO Tariff.  For undispatched Replacement Reserve the user rate shall be calculated by dividing the net cost to ISO of purchasing undispatched Replacement Reserve capacity within the Zone, for the Settlement Period by the ISO’s total Replacement Reserve requirement for the Settlement Period in the Day-Ahead and Hour-Ahead Markets less that which has been self-provided by Scheduling Coordinators within the Zone.  The  net cost to the ISO to purchase undispatched Replacement Reserve capacity is equal to the total cost to the ISO to purchase Replacement Reserve less any amounts payable to the ISO by Scheduling Coordinators for Replacement Reserve bought back from the ISO in the Hour-Ahead Market, less the cost for the Replacement Reserve which was Dispatched.  The undispatched Replacement Reserve user rate for each Settlement Period shall be calculated as follows for each Zone.:

where:
UnDispReplRate = the undispatched Replacement Reserve user rate
ReplPayTotal = the total payments for Replacement Reserve capacity in the Day-Ahead and Hour-Ahead Markets
ReplReceiveTotal = the total amount payable to the ISO by Scheduling Coordinators for Replacement Reserve bought back from the ISO in the Hour-Ahead Market
RRC = the cost of Replacement Reserve capacity dispatched in real time
ReplObligTotal = the ISO’s total Replacement Reserve requirement in the Day-Ahead and Hour-Ahead Markets less that which has been self-provided by Scheduling Coordinators.
	The cost of Replacement Reserve capacity which is dispatched in real time in each Settlement Period in each Zone shall be calculated by multiplying the quantity of Replacement Reserve capacity Dispatched in the Settlement Period in the Zone by the average price paid for Replacement Reserve capacity scheduled in the Day-Ahead Market for the same Zone and Settlement Period calculated as follows:
RRC = PavgRepl * ReplQDisp
where ReplQDisp is the Replacement Reserve capacity Dispatched in the Zone in the Settlement Period and PavgRepl is calculated as follows:
PavgRepl =

where:
ReplPayTotalDA = the total payments for Replacement Reserve for the Day-Ahead Market.
ReplPayTotalHA = the total payments for Replacement Reserve for the Hour-Ahead Market.
ReplQDA = the total quantity of Replacement Reserve capacity provided in the Day-Ahead Market.
ReplQHA = the total quantity of Replacement Reserve capacity provided in the Hour-Ahead Market.
	The undispatched Replacement Reserve capacity charge for each Scheduling Coordinator in the Day-Ahead and Hour-Ahead Markets for each Settlement Period shall be calculated as follows in each Zone:
ReplOblig * UnDispReplRate
where ReplOblig is the Scheduling Coordinator’s obligation for Replacement Reserve in the Settlement Period in the Day-Ahead and Hour-Ahead Markets for which it has not self-provided.
SCHEDULES AND BIDS PROTOCOL AMENDMENTS
Insert the following new section SBP 5.3 after section SBP 5.2.3, as follows:
SBP 5.3	Buy Back of Ancillary Services
Each SC desiring to buy back in the Hour-Ahead Regulation, Spinning Reserve, Non-Spinning Reserve or Replacement Reserve capacity sold to the ISO in the Day-Ahead Market shall do so by submitting in the Hour-Ahead auction for the Settlement Period concerned bids complying with the requirements of SBP 5.1 for the Generating Units/System Units/ Curtailable Demands for which the SC wishes to buy back the Ancillary Service capacity concerned, showing the revised quantity (which may be zero) of the Ancillary Service capacity which the SC wishes to provide in the Hour-Ahead Market from the Generating Units/ System Units/ Curtailable Demands concerned.  The ISO will then calculate from this the Ancillary Services capacity which the SC wishes to buy back.
SCHEDULING PROTOCOL AMENDMENTS
Amend sections SP 9.1 (e) and SP 9.3 as follows:
SP 9.1	Bid Evaluation and Scheduling Principles
(e)	the ISO will require SCs to honor their Day-Ahead Ancillary Services schedules and/or bids when submitting their Hour-Ahead Ancillary Services schedules and/or bids (i.e., if a SC bids (or, conversely, self-provides) a specific Ancillary Service in a Settlement Period in the Day-Ahead Market, that SC will not be allowed to self-provide (or, conversely, bid) the same Ancillary Service in the same Settlement Period in the Hour-Ahead Market, except for any difference between its Day-Ahead and Hour-Ahead requirements for the same Ancillary Service for the same Settlement Period, in which case if the capacity which the SC wishes to bid or self provide is greater in the Hour-Ahead Market than in the Day-Ahead Markets, the difference can be either bid or self-provided.  If capacity which the SC wishes to provide in the Hour-Ahead Market is less than the capacity which it sold to the ISO in the Day-Ahead Market the SC may buy back the difference from the ISO in the Hour-Ahead Market at the Hour-Ahead Market Clearing Price for the same Settlement Period for the Ancillary Service capacity concerned);
SP 9.3	Scheduling Ancillary Services Resources
(e)	Once the ISO has given SCs notice of the Day-Ahead and Hour-Ahead schedules, these schedules represent binding commitments made in the reserve markets between the ISO and the SCs concerned.  However:
(i)	a Scheduling Coordinator who has sold Regulation, Spinning Reserve, Non-Spinning Reserve or Replacement Reserve capacity to the ISO in the Day-Ahead Market may buy back that capacity in whole or in part from the ISO in the Hour-Ahead Market at the Zonal Market Clearing Price for the Ancillary Service for the Settlement Period concerned for the Zone in which the Generating Unit or other resources on behalf of which the Scheduling Coordinator buys back the capacity, are located.  The ISO will purchase the Ancillary Service concerned from another Scheduling Coordinator in the Hour-Ahead Market in accordance with the provisions of the ISO Tariff.
(ii)	a Scheduling Coordinator whose non-self-provided obligation for Regulation, Spinning Reserve, Non-Spinning Reserve or Replacement Reserve for any Zone reduces between the Day-Ahead and Hour-Ahead Market may sell back to the ISO in the Hour-Ahead Market the amount of such Ancillary Service in whole or in part which is in excess of its non-self-provided obligation in the Hour-Ahead Market.  Provided that the ISO has a market for the sale of the Ancillary Service concerned to other Scheduling Coordinators, the price for such a sale back shall be the hourly user rate for the Ancillary Service for the Settlement Period for the Zone concerned in the Hour-Ahead Market.  If the ISO has no market for the sale of the Ancillary Service concerned to other Scheduling Coordinators, the price for the sale back shall be zero.
SETTLEMENT AND BILLING PROTOCOL APPENDIX C AMENDMENTS
Amend sections C 2.1.2, C 2.2.2, and C 3 as follows:
C 2.1.2	Hour-Ahead Market
(a)	Regulation.  When the ISO purchases regulation capacity in the Hour-Ahead Market, Scheduling Coordinators for Generating Units that provide this capacity will receive payment for the Trading Interval of the Hour-Ahead Market.  The payment for a given Generating Unit which provides Regulation capacity over the Trading Interval will be the total quantity of Regulation capacity provided times the zonal Market Clearing Price for that Trading Interval in that Zone.  The required Regulation capacity is defined in the Ancillary Services Requirements Protocol.  This payment for Scheduling Coordinator j for providing Regulation capacity from a resource i in Zone x for Trading Interval t is calculated as follows:

The total Regulation payment for the Trading Interval of the Hour-Ahead Market to each Scheduling Coordinator for all the resources that it represents in a given Zone is calculated by summing all the payments for the resources of the Scheduling Coordinator in the Zone for the Trading Interval and then deducting therefrom any amount payable by the Scheduling Coordinator to the ISO for Regulation bought back by the Scheduling Coordinator from the ISO in the Hour-Ahead Market for the Trading Interval on behalf of resources located in the Zone.  This payment for Scheduling Coordinator j in Zone x for Trading Interval t is calculated as follows:

(b)	Spinning Reserve.  When the ISO purchases Spinning Reserve capacity in the Hour-Ahead Market, Scheduling Coordinators for Generating Units that provide this capacity will receive payments for the Trading Interval of the Hour-Ahead Market.  The payment for a given Generating Unit which provides Spinning Reserve capacity over the Trading Interval will be the total quantity of Spinning Reserve capacity provided times the zonal Market Clearing Price for that Trading Interval in that Zone.  This payment for Scheduling Coordinator j for providing Spinning Reserve capacity from a resource i in Zone x for Trading Interval t is calculated as follows:

The total Spinning Reserve payment to each Scheduling Coordinator for the Trading Interval of the Hour-Ahead Market for all the resources that it represents in a given Zone is calculated by summing all the payments for the resources of the Scheduling Coordinator in the Zone for the Trading Interval and then deducting therefrom any amount payable by the Scheduling Coordinator to the ISO for Spinning Reserve bought back by the Scheduling Coordinator from the ISO in the Hour-Ahead Market for the Trading Interval on behalf of resources located in the Zone.  This payment for Scheduling Coordinator j in Zone x for Trading Interval t is calculated as follows:

(c)	Non-Spinning Reserve.  When the ISO purchases Non-Spinning Reserve capacity in the Hour-Ahead Market, Scheduling Coordinators for Generating Units and Loads that provide this capacity will receive payment for the Trading Interval of the Hour-Ahead Market.  The payment for a given Generating Unit or Load which provides Non-Spinning Reserve capacity over the Trading Interval will be the total quantity of Non-Spinning Reserve capacity provided times the zonal Market Clearing Price for that Trading Interval in that Zone.  This payment for Scheduling Coordinator j for providing Non-Spinning Reserve capacity from a resource i in Zone x for Trading Interval t is calculated as follows:

The total Non-Spinning Reserve payment to each Scheduling Coordinator for the Trading Interval of the Hour-Ahead Market for all the resources that it represents in a given Zone is calculated by summing all the payments for the resources of the Scheduling Coordinator in the Zone for the Trading Interval and then deducting therefrom any amount payable by the Scheduling Coordinator to the ISO for Non-Spinning Reserve bought back by the Scheduling Coordinator from the ISO in the Hour-Ahead Market for the Trading Interval on behalf of resources located in the Zone.  This payment for Scheduling Coordinator j in Zone x for Trading Interval t is calculated as follows:

(d)	Replacement Reserve.  When the ISO purchases Replacement Reserve capacity in the Hour-Ahead Market, Scheduling Coordinators for Generating Units and Loads that provide this capacity will receive payments for the Trading Interval of the Hour-Ahead Market.  The payment for a given Generating Unit or Load which provides Replacement Reserve capacity over the Trading Interval will be the total quantity of Replacement Reserve capacity provided times the zonal Market Clearing Price for that Trading Interval in that Zone.  This payment for Scheduling Coordinator j for providing Replacement Reserve capacity from a resource i in Zone x for Trading Interval t is calculated as follows:

The total Replacement Reserve payment to each Scheduling Coordinator for the Trading Interval of the Hour-Ahead Market for all the resources that it represents in a given Zone is calculated by summing all the payments for the resources of the Scheduling Coordinator in the Zone for the Trading Interval and then deducting therefrom any amount payable by the Scheduling Coordinator to the ISO for Replacement Reserve bought back by the Scheduling Coordinator from the ISO in the Hour-Ahead Market for the Trading Interval on behalf of resources located in the Zone.  This payment for Scheduling Coordinator j in Zone x for Trading Interval t is calculated as follows:

C 2.2.2	Hour-Ahead Market
(a)	Regulation.  The ISO will charge the zonal net cost of providing Regulation capacity that is not self-provided by Scheduling Coordinators, in the Hour-Ahead Market through the application of a charge to each Scheduling Coordinator for the Trading Interval concerned.  This charge will be computed by multiplying the Regulation user rate for the Trading Interval by the Scheduling Coordinators Spinning Reserve obligation, for which it has not self-provided, for the same Period.
The zonal Regulation capacity user rate for the Hour-Ahead Market is calculated by dividing the total cost to ISO of purchasing Regulation capacity within the Zone less any amounts payable to the ISO by Scheduling Coordinators for Regulation bought back from the ISO in the Hour-Ahead Market on behalf of resources located in the Zone, for the  Trading Interval, by the total ISO Regulation capacity obligation for the Trading Interval within the Zone.  The Hour-Ahead Regulation capacity user rate in Zone x for Trading Interval t is calculated as follows:

The Regulation capacity charge for Scheduling Coordinator j in the Hour-Ahead Market in Zone x for Trading Interval t is calculated as follows:
AGCChgHAjxt = (AGCObligHAjxt * AGCRateHAxt)
 - (AGCSellBackjxt * AGCRateHAxt)
(b)	Spinning Reserve.  The ISO will charge the zonal net cost of providing Spinning Reserve capacity that is not self-provided by Scheduling Coordinators, in the Hour-Ahead Market, through the application of a charge to each Scheduling Coordinator for the Trading Interval.  This charge will be computed by multiplying the Spinning Reserve capacity user rate for the Trading Interval by the Scheduling Coordinators Spinning Reserve obligation, for which it has not self-provided, for the same period.
The zonal Spinning Reserve capacity user rate for the Hour-Ahead Market is calculated by dividing the total cost to ISO of purchasing Spinning Reserve capacity within the Zone less any amounts payable to the ISO by Scheduling Coordinators for Spinning Reserve bought back from the ISO in the Hour-Ahead Market on behalf of resources located in the Zone, for the  Trading Interval, by the total ISO Spinning Reserve obligation for the Trading Interval within the Zone.  The Hour-Ahead Spinning Reserve capacity user rate in Zone x for Trading Interval t is calculated as follows:

The Spinning Reserve capacity charge for Scheduling Coordinator j in the Hour-Ahead Market in Zone x for Trading Interval t is calculated as follows:
SpinChgHAjxt = (SpinObligHAjxt * SpinRateHAxt) 
   - (SpinSellBackjxt * SpinRateHAxt)
(c)	Non-Spinning Reserve.  The ISO will charge the zonal net cost of providing Non-Spinning Reserve capacity that is not self-provided by Scheduling Coordinators, in the Hour-Ahead Market, through the application of a charge to each Scheduling Coordinator for the Trading Interval.  This charge will be computed by multiplying the Non-Spinning Reserve capacity user rate for the concerned Trading Interval by the Scheduling Coordinators Non-Spinning Reserve obligation, for which it has not self-provided, for the same period.
The zonal Non-Spinning Reserve capacity user rate for the Hour-Ahead Market is calculated by dividing the total cost to ISO of purchasing Non-Spinning Reserve capacity within the Zone less any amounts payable to the ISO by Scheduling Coordinators for Non-Spinning Reserve bought back from the ISO in the Hour-Ahead Market on behalf of resources in the Zone, for the Trading Interval, by the total ISO Non-Spinning Reserve obligation for the Trading Interval within the Zone.  The Hour-Ahead Non-Spinning Reserve capacity user rate in Zone x for Trading Interval t is calculated as follows:

The Non-Spinning Reserve capacity charge for Scheduling Coordinator j in the Hour-Ahead Market in Zone x for Trading Interval t is calculated as follows:
NonSpinChgHAjxt= (NonSpinObligHAjxt* NonSpinRateHAxt) 
- (NonSpinSellBackjxt* NonSpinRateHAxt)
C 2.2.3	Replacement Reserve
	Only undispatched Replacement Reserve capacity charges are covered within the Ancillary Services calculations.  Dispatched Replacement Reserve capacity charges are covered within the Imbalance Energy calculations in Appendix D.  This enables the ISO to allocate the cost of Dispatched Replacement Reserve capacity to those Scheduling Coordinators who contributed to the Imbalance Energy requiring such Dispatch.
	The ISO will charge the zonal net cost of providing undispatched Replacement Reserve capacity that is not self-provided by Scheduling Coordinators, in the Day-Ahead and Hour-Ahead Markets, through the application of a charge to each Scheduling Coordinator for each Trading Interval.  This charge will be computed by multiplying the undispatched Replacement Reserve capacity user rate for the Trading Interval by the Scheduling Coordinators Replacement Reserve obligation, for which it has not self-provided, for the same Trading Interval.
	The zonal undispatched Replacement Reserve capacity user rate is calculated by dividing the net cost to ISO of purchasing undispatched Replacement Reserve capacity within the Zone, for the Trading Interval, by the total ISO Replacement Reserve obligation for the Trading Interval within the Zone.  The net cost to ISO to purchase undispatched Replacement Reserve capacity is equal to the total cost to ISO to purchase Replacement Reserve capacity less any amounts payable to the ISO by Scheduling Coordinators for Replacement Reserve bought back from the ISO in the Hour-Ahead Market on behalf of resources located in the Zone less the cost for Replacement Reserve capacity which was Dispatched.  The undispatched Replacement Reserve capacity user rate in Zone x for Trading Interval t is calculated as follows:

	The zonal cost of Replacement Reserve capacity which is dispatched in the Real Time Market in a Trading Interval is calculated by multiplying the quantity of Replacement Reserve capacity Dispatched in the Trading Interval in the Zone by the average price paid for Replacement Reserve capacity scheduled in the Day-Ahead Market and the Hour-Ahead Market for the same Zone and Trading Interval.  The cost of Replacement Reserve capacity dispatched in the Real Time Market in Zone x for Trading Interval t is calculated as follows:

	The average price paid for Replacement Reserve capacity in the Day-Ahead Market in Zone x in Trading Interval t is calculated as follows:

	The undispatched Replacement Reserve capacity charge for Scheduling Coordinator j in the Day-Ahead and Hour-Ahead Market in Zone x for Trading Interval t is calculated as follows:
UnDispReplChgjxt = (ReplObligjxt * UnDispReplRatext)
		- (ReplSellBackjxt* UnDispReplRateHAxt)
C 3		Meaning of terms of formulae
C 3.5.1	AGCReceiveHAijxt - $
The payment from Scheduling Coordinator j for buying back from the ISO in the Hour-Ahead Regulation capacity which the ISO had purchased from Scheduling Coordinator j in the Day-Ahead Market from a resource i in Zone x for Trading Interval t.
C 3.8	AGCPayTotalHAjxt - %
The total payment for incremental (additional to Day-Ahead) Regulation capacity to Scheduling Coordinator j in the Hour-Ahead Market in Zone x for Trading Interval t, after deduction of payments from Scheduling Coordinator j for buying back from the ISO in the Hour-Ahead, Regulation capacity which the ISO had purchased from Scheduling Coordinator j in the Day-Ahead Market in Zone x for Trading Interval t.
C 3.13	AGCRateHAxt - $/MW
The Hour-Ahead incremental (additional to Day-Ahead) Regulation capacity user rate charged to Scheduling Coordinators by the ISO in Zone x for Trading Interval t.  Where ASCRateHAxt is applied to ASCSellBackjxt it shall be set at zero if there is no market for the sale by the ISO of the Regulation capacity concerned to other Scheduling Coordinators.
C 3.16.1	AGCSell Backjxt - MW
The decremental (less than Day-Ahead) Regulation obligation in Zone x which the Scheduling Coordinator j sells back to the ISO for Trading Interval t in the Hour-Ahead Market.
C 3.25.1	SpinReceiveHAljxt - $
The payment from Scheduling Coordinator j for buying back from the ISO in the Hour-Ahead, Spinning Reserve capacity which the ISO had purchased from Scheduling Coordinator j in the Day-Ahead Market from a resource i in Zone x for Trading Interval t.
C 3.28	SpinPayTotalHAjxt - $
The total payment to Scheduling Coordinator j for incremental (additional to Day-Ahead) Spinning Reserve capacity in the Hour-Ahead Market in Zone x for Trading Interval t, after deduction of payments from Scheduling Coordinator j for buying back from the ISO in the Hour-Ahead, Spinning Reserve capacity which the ISO had purchased from Scheduling Coordinator j in the Day-Ahead Market in Zone x for Trading Interval t.
C 3.33	SpinRateHAxt - $/MW
The Hour-Ahead incremental (additional to Day-Ahead) Spinning Reserve capacity user rate charged to Scheduling Coordinators by the ISO in Zone x for Trading Interval t.  Where SpinRate HAxt is applied to SpinSellBackjxt it shall be set at zero if there is no market for the sale by the ISO of the Spinning Reserve capacity concerned to other Scheduling Coordinators.
C 3.36.1	SpinSellBackjxt - MW
The decremental (less than Day-Ahead) Spinning Reserve capacity obligation in Zone x which the Scheduling Coordinator j sells back to the ISO for Trading Interval t in the Hour-Ahead Market.
C 3.41.1	NonSpinReceiveHAijxt - $
The payment from Scheduling Coordinator j for buying back from the ISO in the Hour-Ahead, Non-Spinning Reserve capacity which the ISO had purchased from Scheduling Coordinator j in the Day-Ahead Market from a resource i in Zone x for Trading Interval t.
C 3.44	NonSpinPayTotalHAjxt - $
The total payment to Scheduling Coordinator j for providing incremental (additional to Day-Ahead) Non-Spinning Reserve capacity in the Hour-Ahead Market in Zone x for Trading Interval t, after deduction of payments from Scheduling Coordinator j for buying back from the ISO in the Hour-Ahead, Non-Spinning Reserve capacity which the ISO had purchased from Scheduling Coordinator j in the Day-Ahead Market in Zone x for Trading Interval t.
C 3.49	NonSpinRateHAxt - $/MW
The Hour-Ahead incremental (additional to Day-Ahead) Non-Spinning Reserve capacity user rate charged to Scheduling Coordinators by the ISO in Zone x for Trading Interval t.  Where NonSpinRate HAxt is applied to NonSpinSellBackjxt it shall be set at zero if there is no market for the sale by the ISO of the Non-Spinning Reserve capacity concerned to other Scheduling Coordinators.
C 3.51.1	NonSpinSellBackjxt - MW
The decremental (less than Day-Ahead) Non-Spinning Reserve capacity obligation in Zone x which the Scheduling Coordinator j sells back to the ISO for Trading Interval t in the Hour-Ahead Market.
C 3.56.1	ReplReceiveHAijxt - $
The payment from Scheduling Coordinator j for buying back from the ISO in the Hour-Ahead, Replacement Reserve capacity which the ISO had purchased from Scheduling Coordinator j in the Day-Ahead Market from a resource i in the Zone x for Trading Interval t.
C 3.60	ReplPayTotalHAjxt - $
The total payment to Scheduling Coordinator j for providing of incremental (additional to Day-Ahead) Replacement Reserve capacity in the Hour-Ahead Market in Zone x for Trading Interval t, after deduction of payments from Scheduling Coordinator j for buying back from the ISO in the Hour-Ahead, Replacement Reserve capacity which the ISO had purchased from Scheduling Coordinator j in the Day-Ahead Market in Zone x from Trading Interval t.
C 3.61	UnDispReplRatext - $/MW
The Day-Ahead and Hour-Ahead undispatched Replacement Reserve capacity user rate charged to Scheduling Coordinators by the ISO in Zone x for Trading Interval t.  Where UnDispReplRate WAxt is applied to ReplSellBackjxt it shall be set at zero if there is no market for the sale by the ISO of the Replacement Reserve capacity concerned to other Scheduling Coordinators.
C 3.65.1	ReplSellBackjxt - MW
The decremental (less than Day-Ahead) Replacement Reserve capacity obligation in Zone x which the Scheduling Coordinator j sells back to the ISO for Trading Interval t in the Hour-Ahead Market.
III.	CLARIFICATION OF ALLOCATION OF REPLACEMENT RESERVES UNDER VARYING CONGESTION CONDITIONS IN THE 
DAY-AHEAD AND HOUR-AHEAD MARKETS
The ISO’s Settlement system aggregates the total cost for the supply of Replacement Reserve in the Day-Ahead and Hour-Ahead Markets and allocates this cost to Scheduling Coordinators based on allocation formulas set out in the ISO Tariff, including the ISO Protocols.  In the absence of Congestion, the Settlement system allocates these Charges across the entire ISO Control Area.  If there is Congestion in the Day-Ahead and Hour-Ahead Markets, the Settlement software allocates properly such charges on a Zonal basis. 
However, if there is no Congestion in the Day-Ahead Market but there is Congestion in the Hour-Ahead Market (or vice versa) the ISO’s Settlement software allocates charges for Replacement Reserve on a uniform basis (either on a Zonal basis or across the entire Control Area, but not both).
Accordingly the ISO proposes to apply the following rule.  If there is Congestion in the Day-Ahead Market, the ISO will allocate the Replacement Reserve capacity Charges (both Dispatched and Un-Dispatched) on a Zonal basis.  If there is no Congestion in the Day-Ahead Market, the ISO is going to allocate the Replacement Reserve capacity Charges on an ISO Control Area-wide basis (irrespective of whether there is Congestion in the Hour-Ahead Market or not). 
The ISO considers this rule to reflect the fairest methodology for allocating Replacement Reserve capacity Charges, given the software constraints, because it expects Congestion to be identified in most cases in the Day-Ahead Market.  The ISO therefore proposes to amend Sections 2.5.28.4 and 11.2.4.1 of the ISO Tariff and section C2.2.3 of Appendix C and section D2.3 of Appendix D to the Settlement and Billing Protocol accordingly. 
The ISO’s proposed amendments to Section 2.5.28.4 of the ISO Tariff and Section C 2.2.3 of Appendix C to the Settlement and Billing Protocol as follows.
ISO Tariff Amendment
Amend section 2.5.28.4 as follows:
2.5.28.4	Replacement Reserve.  The user rate per unit of purchased Replacement Reserve for each Settlement Period in the Day-Ahead Market and Hour-Ahead Markets for each Zone shall be calculated as shown below.  If there is Congestion in the Day Ahead Market the ISO will allocate the Replacement Reserve capacity Charges (both Dispatched and Un-Dispatched) on a Zonal basis.  If there is no Congestion in the Day Ahead Market the ISO will allocate the Replacement Reserve capacity Charges on a ISO Control Area-wide basis (irrespective of whether there is Congestion in the Hour Ahead Markets or not) and references in Section 2.5.28.4 of the ISO Tariff to “Zone(s)”, “Zonal” and the use of subscript “x” shall be read as referring to “ISO Control Area”.  Dispatched Replacement Reserve capacity charges are recovered by an augmentation to the Imbalance Energy Charge to allocate costs associated with the dispatch of Replacement Reserve to those Scheduling Coordinators who contributed to the Imbalance Energy requiring such dispatch.  The calculation of this augmentation is set forth in Section 11.2.4.1 of this ISO Tariff.  For undispatched Replacement Reserve the user rate shall be calculated by dividing the net cost to ISO of purchasing undispatched Replacement Reserve capacity within the Zone, for the Settlement Period by the ISO’s total Replacement Reserve requirement for the Settlement Period in the Day-Ahead and Hour-Ahead Markets less that which has been self-provided by Scheduling Coordinators within the Zone.  The total cost to the ISO to purchase undispatched Replacement Reserve capacity is equal to the total cost to the ISO to purchase Replacement Reserve less the cost for the Replacement Reserve which was Dispatched.  The undispatched Replacement Reserve user rate for each Settlement Period shall be calculated as follows for each Zone.:

where
UnDispReplRate = the undispatched Replacement Reserve user rate
ReplPayTotal = the total payments for Replacement Reserve capacity in the Day-Ahead and Hour-Ahead Markets
RRC = the cost of Replacement Reserve capacity dispatched in real time
ReplOblig Total = the ISO’s total Replacement Reserve requirement in the Day-Ahead and Hour-Ahead Markets less that which has been self-provided by Scheduling Coordinators.
	The cost of Replacement Reserve capacity which is dispatched in real time in each Settlement Period in each Zone shall be calculated by multiplying the quantity of Replacement Reserve capacity Dispatched in the Settlement Period in the Zone by the average price paid for Replacement Reserve capacity scheduled in the Day-Ahead and the Hour-Ahead Market for the same Zone and Settlement Period calculated as follows:
RRC = PavgRepl * ReplQDisp
where ReplQDisp is the Replacement Reserve capacity Dispatched in the Zone in the Settlement Period and PavgRepl is calculated as follows:
PavgRepl = 
where:
ReplPayTotalDA = the total payments for Replacement Reserve for the Day-Ahead Market.
ReplPayTotalHA = the total payments for Replacement Reserve for the Hour-Ahead Market.
ReplQDA = the total quantity of Replacement Reserve capacity provided in the Day-Ahead Market.
ReplQHA = the total quantity of Replacement Reserve capacity provided in the Hour-Ahead Market.
The undispatched Replacement Reserve capacity charge for each Scheduling Coordinator in the Day-Ahead and Hour-Ahead Markets for each Settlement Period shall be calculated as follows in each Zone:
ReplOblig * UnDispReplRate
where ReplOblig is the Scheduling Coordinator’s obligation for Replacement Reserve in the Settlement Period in the Day-Ahead and Hour-Ahead Markets for which it has not self-provided.
In Section 11.2.4.1 of the ISO Tariff the paragraph titled “Replacement Reserve Dispatch Charge” will be amended as follows:
11.2.4.1	Net Settlements for Imbalance Energy
Replacement Reserve Dispatch Charge
For each Scheduling Coordinator whose Generators falls below its Schedule, or whose Demand exceeds its Schedule, such that the net Schedule is unbalanced, the following additional charge will apply:
RepResDispChrgjt = Djt*RRDispCosti
where:

where:
RRDispCost is defined in Section 2.5.28.4 of this ISO Tariff.
If there is Congestion in the Day-Ahead Market the ISO will allocate the Replacement Reserve Dispatch Charges on a Zonal basis.  If there is no Congestion in the Day-Ahead Market the ISO will allocate the Replacement Reserve Dispatch Charges on a ISO Control Area-wide basis (irrespective of whether there is Congestion in the Hour-Ahead Markets or not). 
	This additional charge (RepResDispChrg) allocates the cost of dispatched Replacement Reserve to Scheduling Coordinators in proportion to their contribution to the need for the dispatch of that Replacement Reserve, as measured by the magnitude of the Energy insufficiency served through the Imbalance Energy market.  The ISO shall develop protocols and procedures for the monitoring of persistent intentional excessive imbalances by Scheduling Coordinators and for the imposition of appropriate sanctions and/or penalties to deter such behavior.  The net balance of the charges attributable to all Scheduling Coordinators represents the Transmission Losses imbalance total for each hourly Settlement Period.
Settlement and Billing Protocol Appendix C Amendments
Amend section C 2.2.3 as follows:
C 2.2.3	Replacement Reserve
Only undispatched Replacement Reserve capacity charges are covered within the Ancillary Services calculations.  Dispatched Replacement Reserve capacity charges are covered within the Imbalance Energy calculations in Appendix D.  This enables the ISO to allocate the cost of Dispatched Replacement Reserve capacity to those Scheduling Coordinators who contributed to the Imbalance Energy requiring such Dispatch.
If there is Congestion in the Day-Ahead Market the ISO will allocate the Replacement Reserve capacity Charges (both Dispatched and Un-Dispatched) on a Zonal basis.  If there is no Congestion in the Day Ahead Market the ISO will allocate the Replacement Reserve capacity Charges on a ISO Control Area-wide basis (irrespective of whether there is Congestion in the Hour Ahead Markets or not) and references in C2.2.3 of this Appendix C to Settlements and Billing Protocol to “Zone(s)”, “Zonal” and the use of subscript “x” shall be read as referring to “ISO Control Area”. 
The ISO will charge the zonal cost of providing undispatched Replacement Reserve capacity that is not self-provided by Scheduling Coordinators, in the Day-Ahead and Hour-Ahead Markets, through the application of a charge to each Scheduling Coordinator for each Trading Interval.  This charge will be computed by multiplying the undispatched Replacement Reserve capacity user rate for the Trading Interval by the Scheduling Coordinators Replacement Reserve obligation, for which it has not self-provided, for the same Trading Interval.
The zonal undispatched Replacement Reserve capacity user rate is calculated by dividing the total cost to ISO of purchasing undispatched Replacement Reserve capacity within the Zone, for the Trading Interval, by the total ISO Replacement Reserve obligation for the Trading Interval within the Zone.  The total cost to ISO to purchase undispatched Replacement Reserve capacity is equal to the total cost to ISO to purchase Replacement Reserve capacity less the cost for Replacement Reserve capacity which was Dispatched.  The undispatched Replacement Reserve capacity user rate in Zone x for Trading Interval t is calculated as follows:

The zonal cost of Replacement Reserve capacity which is dispatched in the Real Time Market in a Trading Interval is calculated by multiplying the quantity of Replacement Reserve capacity Dispatched in the Trading Interval in the Zone by the average price paid for Replacement Reserve capacity scheduled in the Day-Ahead Market and the Hour-Ahead Market for the same Zone and Trading Interval.  The cost of Replacement Reserve capacity dispatched in the Real Time Market in Zone x for Trading Interval t is calculated as follows:

	The average price paid for Replacement Reserve capacity in the Day-Ahead Market in Zone x in Trading Interval t is calculated as follows:

	The undispatched Replacement Reserve capacity charge for Scheduling Coordinator j in the Day-Ahead and Hour-Ahead Market in Zone x for Trading Interval t is calculated as follows:
.
Amend section D2.3 of Appendix D to the Settlement and Billing Protocol as follows:
D2.3	Replacement Reserve Capacity Dispatch Charge
The Replacement Reserve Capacity Dispatch Charge (RRDC) for Scheduling Coordinator j in Trading Interval t is calculated using the following formula:

If there is Congestion in the Day Ahead Market the ISO will allocate the Replacement Reserve Capacity Dispatch Charges on a Zonal basis.  If there is no Congestion in the Day Ahead Market the ISO will allocate the Replacement Reserve Capacity Dispatch Charges on a ISO Control Area-wide basis (irrespective of whether there is Congestion in the Hour Ahead Markets or not). 
IV.  BLACK START AND VOLTAGE SUPPORT AMENDMENTS
The principal purpose of the amendments to the Black Start and Voltage Support sections in the ISO Tariff is to conform the ISO Tariff wording to the arrangements reached by the ISO and providers of Black Start and Voltage Support.  These arrangements are the product of extensive negotiations and, because of time pressures, the exact details and ramifications of the final outcome could not be reflected accurately in the ISO Tariff.  It should be noted, however, that these arrangements are already reflected in the ISO Settlement and Billing Protocol (Appendix G is of particular relevance to these issues), and the proposed amendments seek to conform the ISO Tariff provisions to the contractual arrangements between the parties (as already reflected in the ISO Settlement and Billing Protocol).
The proposed amendments to the Black Start provisions: (a) clarify that Black Start services may be provided to the ISO either by Black Start Generators or by owners of Reliability Must-Run Units; (b) clarify that providers of Black Start service currently will not receive any payment for Black Start capacity but will receive payment for Energy output in the event that they are called upon to provide Black Start Energy; and (c) clarify that Black Start Generators will be paid directly by the ISO for their services whereas owners of Reliability Must-Run Units will be paid by the ISO through their Scheduling Coordinators.
The proposed amendments to Voltage Support provisions: (a) clarify that long term Voltage Support is provided to the ISO by owners of Reliability Must-Run Units; (b) clarify that payments for long term Voltage Support to owners of Reliability Must-Run Units will be made by the ISO through their Scheduling Coordinators; (c) clarify the formula for calculating payments for short term additional Voltage Support; and (d) provide for the ISO to recover charges for Voltage Support on a Zonal basis rather than on a Control Area basis (which amendment will allow the charges to more accurately reflect the localized character of Voltage Support).
ISO TARIFF AMENDMENTS
Amend sections 2.5.18, 2.5.19, 2.5.27.6, 2.5.28.5 and 2.5.28.6 as follows:
2.5.18	Voltage Support.
As of the ISO Operations Date, the ISO will contract for Voltage Support service with the owners of Reliability Must-Run Units.  Payments for public utilities under the FPA shall be capped at the FERC authorized cost based rates unless and until FERC authorizes different pricing.  The ISO shall pay owners of Reliability Must-Run units for long term Voltage Support through their Scheduling Coordinators.
	In addition, any Participating Generator who is producing Energy shall, upon the ISO’s specific request, provide reactive energy output outside the Participating Generator’s Voltage Support obligation defined in Section 2.5.3.4.
	The ISO shall select Participating Generator’s Generating Units which have been certified for Voltage Support to provide this additional Voltage Support.  Subject to any locational requirements, the ISO shall select the Generating Units from a computerized merit order stack to back down to produce additional Voltage Support in each location where Voltage Support is needed.
	The ISO shall pay to the Scheduling Coordinator for that Participating Generator the opportunity cost of reducing Energy output to enable reactive energy production.  This opportunity cost shall be:
	Max{0, Zonal Hourly Ex Post Price - Generating Unit bid price} x reduction in Energy output (MW).
If necessary, the ISO shall develop a regulatory cost based determination of marginal operating cost to be used in place of the Generating Unit bid price.
2.5.19	Black Start Capability and Energy Output.
As of the ISO Operations Date, the ISO will contract for Black Start capability and Energy with owners of Reliability Must-Run Units and  Black Start Generators.  Public utilities under the FPA will be paid rates capped at the FERC authorized cost base rates unless and until FERC authorizes different pricing.  The ISO shall pay owners of Reliability Must-Run Units for Black Start Energy output through their Scheduling Coordinators.  The ISO shall pay Black Start Generators for Black Start Energy output directly.
2.5.27.6  Black Start.
Quantities.  The following quantities shall be used in the Settlement process:

EnQBSijt = Energy output from Black Start  made by Generating Unit i from Scheduling Coordinator j (or Black Start Generator j, as the case may be) for Settlement Period t, pursuant to the ISO's order to produce.
Prices.  The prices used in the Settlement process are those described in the contracts referred to in section 2.5.19.
Penalty = penalty described in section 2.5.26.
Payments.  
Scheduling Coordinators for owners of Reliability Must-Run Units (or Black Start Generators, as the case may be) shall receive the following payments for Energy output from Black Start facilities:
BSENijt = (EnQBSijt*EnBidijt )+BSSUPijt
where BSSUPijt is the start-up payment for a Black Start successfully made by Generating Unit i of Scheduling Coordinator j (or Black Start Generator j) in Trading Interval t calculated in accordance with the applicable Reliability Must-Run Contract (or the Interim Black Start agreement as the case may be).
2.5.28.5	Voltage Support.  The short term market Voltage Support user rate for Settlement Period t for Zone x shall be calculated as follows:

VSSTxijt = Voltage Support payment to Scheduling Coordinator i in respect of Generating Unit i in Zone x in the short-term market applicable to Settlement Period t.
QChargeVSxjt = charging quantity for Voltage Support for Scheduling Coordinator j for Settlement Period t in Zone x equal to the total metered Demand in Zone x (including exports to neighboring Control Areas) by Scheduling Coordinator j for Settlement Period t.
The monthly long term Voltage Support contract user rate for Settlement Period t for Zone x shall be calculated as follows:

where:
VSLTxijm = 	long term Voltage Support contract payment  to Scheduling Coordinator j for owner of Reliability Must-Run Unit i in Zone x for month m.
2.5.28.6  Black Start .

  QChargeBlackstartjt = charging quantity for Black Start for Scheduling Coordinator j for Settlement Period t equal to the total metered Demand (including exports to neighboring Control Areas) by Scheduling Coordinator j  for Settlement Period t.
The Black Start Energy payment user rate for Settlement Period t will be calculated as follows:
BSRatet = 
where BSEnijt is the ISO payment to Scheduling Coordinator j for owner of Reliability Must-Run Unit (or to Black Start Generator j, as the case may be)  for Generating Unit i providing Black Start Energy in Settlement Period t.

The Black Start Energy user charge for Settlement Period t for Scheduling Coordinator j will be calculated as follows:
BSChargejt = BSRatet * QchargeBlackStartjt
ISO TARIFF APPENDIX A AMENDMENT
Add the following definition to ISO Tariff Appendix A:
Black Start Generator	a Participating Generator in its capacity as party to an Interim Black Start Agreement with the ISO for the provision of Black Start services, but shall exclude Participating Generators in their capacity as providers of Black Start services under their Reliability Must-Run Contracts.
	
SETTLEMENT AND BILLING PROTOCOL APPENDIX G AMENDMENTS
Amend sections G 2.1, G 2.2, and G 3.1 through G 3.10 as follows:
G 2.1.1	Lost Opportunity Cost Payments (supplemental reactive power) to Scheduling Coordinators for Generating Units
When the ISO obtains additional Voltage Support by instructing a Generating Unit to operate outside its mandatory MVar range by reducing its MW output the ISO will select Generating Units based on their Supplemental Energy Bids ($/MWh).  Subject to any locational requirements the ISO will select the Generating Unit with the highest decremental Supplemental Energy Bid to reduce MW output by such amount as is necessary to achieve the instructed MVar reactive energy production.  Each Trading Interval the ISO will pay Scheduling Coordinator j for that Generating Unit i in Zone x, the lost opportunity cost ($) resulting from the reduction of MW output in Trading Interval t in accordance with the following formula:
VSSTxijt= Max {0,Pxt - Supxdecit}*DECxit
G 2.1.2	Long term contract payments to Scheduling Coordinators for Reliability Must-Run Units for Generating Units and other Voltage Support Equipment
The ISO will pay Scheduling Coordinator j for the provision of Voltage Support from its Reliability Must-Run Units located in Zone x in month m a sum (VSLTxjm) consisting of:
(a)	the total of the Ancillary Service Pre-empted Dispatch Payments if the ISO has decreased the output of the Reliability Must-Run Units for the provision of Voltage Support outside the power factor range of the Reliability Must-Run Unit in any Trading Interval in month m and/or
(b)	(if applicable) the total payments for the provision of Voltage Support in month m requested by the ISO from the synchronous condensers of the Reliability Must-Run Units,
calculated in each case in accordance with the terms of the relevant Reliability Must-Run Contract.  Data on these payments will not be generated by the ISO.  Such data will be based on the invoices issued by the Owners of Reliability Must-Run Generating Units pursuant to their Reliability Must-Run Contracts and will be verified by the ISO.
G 2.2	Charges to Scheduling Coordinators for Voltage Support
G 2.2.1	User Rate
The user rate ($/MWh) for the lost opportunity cost for voltage support referred to in G2.1.1 in Zone x for Trading Interval t will be calculated using the following formula:

The user rate ($/MWh) for month m for long term voltage support referred to in G2.1.2 in Zone x will be calculated using the following formula:

G 2.2.2	Voltage Support Charges
The lost opportunity cost Voltage Support charge ($) payable to recover the sums under G2.1.1 for Zone x for Trading Interval t for Scheduling Coordinator j will be calculated using the following formula:

The monthly long term voltage support charge ($) payable to recover sums under G2.1.2 for Zone x for month m for Scheduling Coordinator j will be calculated using the following formula:

G 3	Meaning of Terms in the Formulae
G 3.1	VSSTxijt	($)
The lost opportunity cost paid by the ISO to Scheduling Coordinator j for Generating Unit i in Zone x, resulting from the reduction of MW output in Trading Interval t.
G 3.2	Pxt		($/MWh)
The Hourly Ex Post price for Imbalance Energy in Trading Interval t in Zone x.
G 3.3	Supxdecit	($/MWh)
The Supplemental Energy Bid submitted by Scheduling Coordinator j for Generating Unit i in Zone x in Trading Interval t, whose output is reduced by the ISO to provide additional short term Voltage Support.
G 3.4	Decxit		(MW)
The reduction in MW by Scheduling Coordinator j for Generating Unit i in Zone x in Trading Interval t, in order to provide short term additional Voltage Support.
G 3.5	VSLTxjm	($)
The payment from the ISO to Scheduling Coordinator j for its Reliability Must-Run Units in Zone x for Voltage Support in month m calculated in accordance with the relevant Reliability Must-Run Contract.
G 3.6	VSSTRatext 	($/MWh)
The Trading Interval lost opportunity cost Voltage Support user rate charged by the ISO to Scheduling Coordinators for Trading Interval t for Zone x.
G 3.7	VSLTRatexm	($/MWh)
The monthly long term voltage support user rate charged by the ISO to Scheduling Coordinators for month m for Zone x.
G 3.8	QChargeVSxjt (MWh)
The charging quantity for Voltage Support for Scheduling Coordinator j for Trading Interval t in Zone x equal to the total metered Demand (including exports from neighboring Control Areas) for Scheduling Coordinator j in Zone x for Trading Interval t.
G 3.9	VSSTChargexjt	($)
The lost opportunity cost Voltage Support user charge for Zone x for Trading Interval t for Scheduling Coordinator j.
G 3.10	VSLTChargexjm	($)
The long term charge for voltage support for month m for Zone x for Scheduling Coordinator j.
V.  RELIABILITY MUST-RUN AMENDMENTS
These changes clarify a potentially confusing provision in the ISO Tariff regarding the relationship between the payments received by the ISO from Scheduling Coordinators and the amounts paid by Participating TOs in relation to Reliability Must-Run services.  The Reliability Must-Run Contracts provide that the ISO will pay the net difference between amounts received by owners of Reliability Must-Run Units from the market (their Scheduling Coordinators) and the amounts owed under the Reliability Must-Run Contract.  The proposed deletion in Section 5.2.7 of the ISO Tariff eliminates any inference that netting applies only to Ancillary Services revenues.
Additionally, Appendix H to the Settlement and Billing Protocol is being amended to include two payment items included in the Reliability Must-Run Contracts but not in the equations in Appendix H.  Specifically, certain equations in Appendix H are being amended to include separate items for credits to be made against amounts due to Reliability Must-Run Unit owners from their Scheduling Coordinators for Energy delivered pursuant to an ISO Dispatch notice issued in real time.  Other changes correct typographical errors.
ISO TARIFF AMENDMENT
Amend section 5.2.7 as follows:
5.2.7	Reliability Must-Run Charge.  The ISO shall recover the costs it incurs through payments under each Reliability Must-Run Contracts from the utility that is a party to the TCA in whose Service Area the Reliability Must-Run Generating Unit is located.  The ISO shall prepare and send to each such utility in accordance with the relevant ISO Protocols an invoice in respect of all such costs incurred under all such contracts relating to that utility’s Service Area.  Each such utility shall pay the ISO’s invoices by the Payment Date, in default of which interest shall become payable at the ISO Default Interest Rate.
Settlement and billing protocol appendix h amendments
H 2	Calculation of Payments and Charges
H 2.1	Reliability Must-Run Payments.
Invoices submitted by Reliability Must-Run Owners to the ISO must be calculated as follows:
(a)	Agreement A:
The Reliability Must-Run Payment under Agreement A for each month for each Owner shall be the total of the payments for that month for each Reliability Must-Run Unit owned by the Owner to which the Conditions of Must-Run Agreement A apply calculated in accordance with those Conditions.  The Agreement A payment for Reliability Must-Run Owner o for Reliability Must-Run Unit u for month m shall be calculated as follows:

The total payment to each Owner for Reliability Must-Run services under Agreement A for a given month shall be calculated by summing all the payments for the month for the Reliability Must-Run Units owned by the Owner to which Agreement A applies.  The payment for Owner o for month m shall be calculated as follows:

(b)	Agreement B
The Reliability Must-Run Payment under Agreement B for each month for each Owner shall be the total of the payments for that month for each Reliability Must-Run Unit owned by the Owner to which the Conditions of Must-Run Agreement B apply calculated in accordance with those Conditions.  The Agreement B payment for Reliability Must-Run Owner o for Reliability Must-Run Unit u for month m shall be calculated as follows:

The total payment to each Owner for Reliability Must-Run services under Agreement B for a given month shall be calculated by summing all the payments for the month for the Reliability Must-Run Units owned by the Owner to which Agreement B applies.  The payment for Owner o for month m shall be calculated as follows:

(c)	Agreement C
The Reliability Must-Run Payment under Agreement C for each month for each Owner shall be the total of the payments for that month for each Reliability Must-Run Unit owned by the Owner to which the Conditions of Must-Run Agreement C apply calculated in accordance with those Conditions.  The Agreement C payment for Reliability Must-Run Owner o for Reliability Must-Run Unit u for month m shall be calculated as follows:

The total payment to each Owner for Reliability Must-Run services under Agreement C for a given month shall be calculated by summing all the payments for the month for the Reliability Must-Run Units owned by the Owner to which Agreement C applies.  The payment for Owner o for month m shall be calculated as follows:

(d)	Total Payment
The total amount payable to each Owner for each month for Reliability Must-Run services shall be the total of the amounts due to the Owner under Agreements A, B and C for that month.  The total payment for Reliability Must-Run Owner o for month m shall be calculated as follows:

H 3	Meaning of terms of formulae
H 3.3	Euot			(MWh)
The Energy Delivered by Reliability Must-Run Unit u owned by Reliability Must-Run Owner o in Settlement Period t pursuant to a Dispatch Notice or an ISO's Request under the Conditions of Must-Run Agreement applicable to Reliability Must-Run Unit u.
H 3.6.1	SCACuot		($)
The Scheduling Coordinator administration charge payable by Reliability Must-Run Owner o for Reliability Must-Run Unit u for Settlement Period t under the Conditions of Must-Run Agreement applicable to Reliability Must-Run Unit u.
H 3.7	HOFuom		($)
The Hourly Operating Fuel Costs for Reliability Must-Run Unit u owned by Reliability Must-Run Owner o for Energy Delivered pursuant to a Dispatch Notice or an ISO’s Request under the Conditions of Must-Run Agreement applicable to Reliability Must-Run Unit u in month m calculated in accordance with Schedule C to the Conditions of Must-Run Agreement.  This figure must be broken down to show that the calculation accords with Schedule C.
H 3.9	SUPCuot		($)
The Start-up and Shutdown Power Costs for Reliability Must-Run Unit u owned by Reliability Must-Run Owner o for Start-ups made in month m pursuant to a Dispatch Notice or an ISO’s Request under the Conditions of Must-Run Agreement applicable to Reliability Must-Run Unit u, calculated in accordance with Schedule D to the Conditions of Must-Run Agreement.  This figure must be broken down to show that the calculation accords with Schedule D.
H 3.10	OSUCuom	($)
The other Start-up costs for Reliability Must-Run Unit u owned by Reliability Must-Run Owner o for Start-ups made in month m pursuant to a Dispatch Notice or an ISO’s Request under the Conditions of Must-Run Agreement applicable to Reliability Must-Run Unit u, calculated in accordance with Schedule D to the Conditions of Must-Run Agreement.  This figure must be broken down to show that the calculation accords with Schedule D.
H 3.11	AGCuot		($)
The amount payable under the Conditions of Must-Run Agreement A applicable to Reliability Must-Run Unit u owned by Reliability Must-Run Owner o for Regulation capacity Delivered by Reliability Must-Run Unit u in Settlement Period t pursuant to a Dispatch Notice or ISO's Request issued by the ISO under the Conditions of Must-Run Agreement.
H 3.12	SRuot			($)
The amount payable under the Conditions of Must-Run Agreement A applicable to Reliability Must-Run Unit u owned by Reliability Must-Run Owner o for Spinning Reserve Capacity Delivered by Reliability Must-Run Unit u in Settlement Period t pursuant to a Dispatch Notice or ISO's Request issued by the ISO under the Conditions of Must-Run Agreement.
H 3.13	NSRuot			($)
The amount payable under the Conditions of Must-Run Agreement A applicable to Reliability Must-Run Unit u owned by Reliability Must-Run Owner o for Non-Spinning Reserve Capacity Delivered by Reliability Must-Run Unit u in Settlement Period t pursuant to a Dispatch Notice or ISO's Request issued by the ISO under the Conditions of Must-Run Agreement.
H 3.14	RRuot			($)
The charge under the Conditions of Must-Run Agreement A applicable to Reliability Must-Run Unit u owned by Reliability Must-Run Owner o for Replacement Reserve Capacity Delivered by Reliability Must-Run Unit u in Settlement Period t pursuant to a Dispatch Notice or ISO's Request issued by the ISO under the Conditions of Must-Run Agreement.
H 3.15	VSuot			($)
The amount payable under the Conditions of Must-Run Agreement applicable to Reliability Must-Run Unit u owned by Reliability Must-Run Owner o for additional Voltage Support Delivered by Reliability Must-Run Unit u in Settlement Period t pursuant to a Dispatch Notice or ISO's Request issued by the ISO under the Conditions of Must-Run Agreement.  This will be either the Ancillary Service Pre-empted Dispatch Payment or the payment for Voltage Support from synchronous condensers, calculated in each case in accordance with the terms of the applicable Conditions of Must-Run Agreement.
H 3.16	ASPDPuot		($/MWh)
The amount payable under the Conditions of Must-Run Agreement applicable to Reliability Must-Run Unit u owned by Reliability Must-Run Owner o for reducing its Scheduled output in order to Deliver Regulation, Spinning Reserve, Non-Spinning Reserve or Replacement Reserve capacity in Settlement Period t pursuant to a Dispatch Notice or ISO’s Request issued by the ISO under the Conditions of Must-Run Agreement.
H 3.16.1	EAuot			(MWh)
The Energy Delivered by Reliability Must-Run Unit u owned by Reliability Must-Run Owner o in Settlement Period t pursuant to a Dispatch Notice or an ISO’s Request issued in the Day-Ahead or the Hour-Ahead under the Conditions of Must-Run Agreement applicable to Reliability Must-Run Unit u.
H 3.17	SCPuot		($/MWh)
The price payable to Reliability Must-Run Unit Owner o from its Scheduling Coordinator for Energy scheduled to be delivered in Settlement Period t by Reliability Must-Run Unit u pursuant to a Dispatch Notice or ISO’s Request issued by the ISO under the Conditions of Must-Run Agreement applicable to Reliability Must-Run Unit u.  This is the Energy weighted average of the decremental Adjustment Bids accepted by the ISO to accommodate Reliability Must-Run Generation and to relieve Intra-Zonal Congestion as described in Appendix B to SABP.
H 3.18	SCASCPuot		($/MWh)
The price payable to Reliability Must-Run Unit Owner o from its Scheduling Coordinator for Regulation, and/or Spinning Reserve, and/or Non-Spinning Reserve, and/or Replacement Reserve capacity Delivered in Settlement Period t by Reliability Must-Run Unit u pursuant to a Dispatch Notice or ISO’s Request issued by the ISO under the Conditions of Must-Run Agreement applicable to Reliability Must-Run Unit u.
H 3.19.1	ERuot			(MWh)
The Energy Delivered by Reliability Must-Run Unit u owned by Reliability Must-Run Owner o in Settlement Period t pursuant to a Dispatch Notice or an ISO’s Request issued in Real Time under the Conditions of Must-Run Agreement applicable to Reliability Must-Run Unit u.
H 3.19.2	Pxuot			($/MWh)
The Hourly Ex Post Price for Settlement Period t for the Zone in which Reliability Must-Run Unit u owned by Reliability Must-Run Owner o is located.
H 4	Data Input/Output
Term	Units	Variable Name	Input or Output	Detail Required	
RMRPayAuom	$	RMR Unit Payment under A	Output	By Unit	
RPRuot	$/MWh	Reliability Payment Rate	Input	By Unit
By Settlement Period	
Euot	MWh	Non-Market Transaction Energy Delivered 	Input	By Unit
By Settlement Period	
EMuot	lb.	Emissions Produced	Input	By Unit
By Settlement Period	
ERuot	$/lb.	Emissions rate	Input	By Unit
By Settlement Period	
HVO&Muot	$/MWh	Variable O&M Rate	Input	By Unit
By Settlement Period	
SCACuot	$	SC Admin. Charge	Input	By Unit	
HOFuom	$	Hourly Operating Fuel Costs	Input	By Unit	
SUFCuom	$	Startup Fuel Costs	Input	By Unit	
SUPCuom	$	Startup and Shutdown Power Costs	Input	By Unit	
OSUCuom	$	Shutdown Power Costs	Input	By Unit	
AGCuot	$	Regulation Payment due	Input	By Unit
By Settlement Period	
SRuot	$	Spinning Reserve Payment due	Input	By Unit
By Settlement Period	
NSRuot	$	Non-Spinning Reserve Payment due	Input	By Unit
By Settlement Period	
RRuot	$	Replacement Reserve Payment due	Input	By Unit
By Settlement Period	
VSuot	$	Voltage Support Payment due	Input	By Unit
By Settlement Period	
ASPDP	$/MWh	Ancillary Service Pre-empted Dispatch Payment	Input	By Unit
By Settlement Period	
EAuot	MWh	Energy Requested
DA and HA	Input	By Unit
By Settlement Period	
SCPuot	$	Scheduling Coordinator’s Energy Price	Input	By Unit
By Settlement Period	
SCASCP	$/MW	Scheduling Coordinator’s Ancillary Service Capacity Price	Input	By Unit
By Settlement Period	
SCASEP	$/MWh	Scheduling Coordinator’s Ancillary Service Energy Price	Input	By Unit
By Settlement Period	
ERuot	MWh	Energy Requested in Real Time	Input	By Unit
By Settlement Period	
Pxuot	$/MWh	Zonal Hourly Ex Post Price	Input	By Unit
By Settlement Period	
RMRPayTotalAom	$	Total RMR Payment under A	Output		
OPAom	$	Other A Payment	Input		
IAA	$	Interest on adjustments	Input		
IDA	$	Interest on unpaid and disputed amounts	Input		
RMRPayBuom	$	RMR Unit Payment under B	Output	By Unit	
APuot	MWh	Availability Payment	Input	By Unit
By Settlement Period	
PXMt	$/MWh	PX Market Clearing Price	Input		
EMTuot	MWh	Market Transaction Energy	Input	By Unit
By Settlement Period	
RMRPayTotalBom	$	Total RMR Payment under B	Output		
OPBom	$	Other B Payment	Input		
IAB	$	Interest on adjustments	Input		
IDB	$	Interest on unpaid and disputed amounts	Input		
RMRPayCuom	$	RMR Unit Payment under C	Output	By Unit	
RMRPayTotalCom	$	Total RMR Payment under C	Output		
OPCom	$	Other C Payment	Input		
IAC	$	Interest on adjustments	Input		
IDC	$	Interest on unpaid or disputed amounts	Input		
RMRCnmu	$	RMR Charge per Unit	Output	By Unit	
RMRPaynmu	$	RMR Unit Payments	Input	By Unit	
Total RMRCnm	$	Total RMR Charge	Output		

VI.  IMBALANCE ENERGY CALCULATION AMENDMENTS
The purpose of these amendments is to clarify the definitions of the terms for actual exports (“Ea “) and actual imports (“Ia “) which are used in the calculation of Imbalance Energy.  Similarly, the definitions of metered imports (“Ik”), metered exports (“Ek “) and metered Generation (“Gk") used in the calculation of Unaccounted for Energy are clarified to show that they relate to metered (as opposed to scheduled) imports, exports and Generation respectively.
ISO TARIFF AMENDMENTS
In section 11.2.4.1 the definitions of Ia and Ea are amended as follows: 
11.2.4.1.  Net Settlements for Imbalance Energy.
la 	=	sum of actual Energy import through Scheduling Point q.
Ea 	=	sum of actual Energy export through Scheduling Point q -
Also in section 11.2.4.1, the definitions of Ik, Ek and Gk  for the Unaccounted for Energy Charge are amended as follows:
Unaccounted for Energy Charge
Ik -- MWh
The total metered imports into utility service territory k in Settlement Period t.
Ek -- MWh
The total metered exports from utility service territory k in Settlement Period t.
Gk -- MWh
The total metered Generation in Settlement Period t in utility service territory k.
SETTLEMENT AND BILLING PROTOCOL APPENDIX D AMENDMENTS
The same amendments to the definitions of Ik, Ek and Gk are made to sections D 3.31, D 3.33, and D 3.34 of the Settlement and Billing Protocol as follows:
D 3.31	Gk	=	MWh
The total metered Generation in Trading Interval t in utility service territory k.
D 3.33	lk	=	MWh
The total metered imports into utility service territory k in Trading Interval t.
D 3.34	Ek	=	MWh
The total metered exports from utility service territory k in Trading Interval t.
VII.  CALCULATION OF USAGE CHARGE AND METHODOLOGY FOR APPLYING DEBITS TO PARTICIPATING TOS
The purpose of the changes to the Usage Charge sections in the ISO Tariff and Settlement and Billing Protocol is twofold.  First, the equations for the calculation of the Usage Charge (and rebates) to Scheduling Coordinators can be expressed in a simpler and more accurate form.  The changes in sections E 2.1 and E 2.2 of the Settlement and Billing Protocol reflect this.
Second, under normal operating conditions, the ISO will remit the net Usage Charge revenues collected from Scheduling Coordinators for each Inter-Zonal Interface based on Participating TOs’ ownership of the interface.  However, the description of payments to be made to Participating TOs under Section 7.3.1.6 of the ISO Tariff and in Appendix E, Usage Charge Computation, to the Settlement and Billing Protocol requires further clarification.  Thus, this amendment includes changes to both referenced provisions. 
In the course of testing the ISO’s software, it became apparent that, under certain conditions, the net Usage Charge revenues payable to Participating TOs may be reduced and as a result Participating TOs may incur a charge.
ISO management discussed this issue with the Participating TOs and with the Scheduling Coordinators.  Both groups advised the ISO management that during the development of the ISO system, stakeholders had agreed that the Participating TOs should not incur such charges.  The ISO management reported the matter to the ISO Board at the regularly-scheduled meeting on January 21 (and the night before in the Grid Reliability and Operations Committee meeting).
The Board directed ISO management to examine possible options to eliminate the Participating TO debits, including by way of manual work-arounds, until the software can be modified.  Unfortunately, a feasible manual work-around does not exist at this time, and will not exist as of the ISO Operations Date.  The ISO has taken action to ensure that the software will be modified as soon as possible to eliminate charges to Participating TOs.  However, until such time as the software has been modified and tested, Participating TOs will be debited under the conditions described below.
Calculating the net Usage Charge revenues under Section 7.3.1.6 of the ISO Tariff involves offsetting Usage Charges payable by Scheduling Coordinators scheduling in the direction of the Congestion from those scheduling in the direction opposite to Congestion (thereby helping relieve Congestion across the particular Inter-Zonal Interface).  Further clarification is needed to cover instances in which transmission capability is reduced for the Hour-Ahead Market after the Day-Ahead Market has closed and Scheduling Coordinators have been charged for Congestion.
When Available Transfer Capacity in a Congested Inter-Zonal Interface is reduced after the issuance of Final Schedules in the Day-Ahead Market and, as a result, Congestion conditions constrain Final Day-Ahead Schedules, then Congestion algorithms will produce debits (charges) to Participating TOs.  This condition can occur as a result of: 
•	Participating TOs instructing the ISO to reduce interface limits based on operating conditions, after the issuance of Final Day-Ahead Schedules; or

•	Unscheduled transmission system outages (i.e. Forced Outages) that limit a given Inter-Zonal Interface transfer capacity after the ISO’s issuance of Final Day-Ahead Schedules.
Such debits (charges) to Participating TOs will be apportioned to those Scheduling Coordinators whose Final Day-Ahead Schedules were reduced and will be a deduction in the calculation of such Participating TOs’ net entitlement to Usage Charges for Hour-Ahead Congestion.
The proposed amendments reflect that Participating TOs’ debits in the Hour-Ahead Market will be limited to circumstances in which Congestion is found and transfer limits are reduced.  If Inter-Zonal Interface restrictions remain, the following Day-Ahead Market will not result in further debits to Participating TOs.
This concept is reflected in the proposed amendments to Section 7.3.1.6 of the ISO Tariff and Appendix E to the Settlement and Billing Protocol.
This concept necessitates changes to Section 7.3.1.6 of the ISO Tariff and Appendix E to the Settlement and Billing Protocol which are revised as follows.
ISO TARIFF AMENDMENTS
Amend Section 7.3.1.6 of the ISO Tariff as follows:
7.3.1.6	ISO Disbursement of Net Usage Charge Revenues.  The ISO will determine the net Usage Charges on an interface-by-interface basis by subtracting the Usage Charge fees paid to Scheduling Coordinators from the Usage Charge fees paid by Scheduling Coordinators.  The net Usage Charge revenues collected by the ISO for each Inter-Zonal Interface shall be, subject to the provisions of Section 7.3.1.7 of the ISO Tariff, paid to Participating TOs who own the Inter-Zonal Interfaces (to be credited in turn by them to their Transmission Revenue Balancing Account).
Add new Section 7.3.1.7 as follows:
7.3.1.7. ISO Debit of Net Usage Charge Revenues.  If, after the issuance of Final Day-Ahead Schedules by the ISO, (a) Participating Transmission Owners instruct the ISO to reduce interface limits based on operating conditions or (b) an unscheduled transmission outage occurs and as a result of either of those events, Congestion is increased and Available Transfer Capacity is decreased in the Inter-Zonal Interface in the Hour-Ahead Market, the ISO shall charge the Participating Transmission Owners with an amount equal to the net Usage Charge revenues in respect of reductions of Available Transfer Capacity across the Congested Inter-Zonal Interface (such amount to be debited by them in turn from their Transmission Revenue Balancing Account).
SETTLEMENT AND BILLING PROTOCOL APPENDIX E AMENDMENTS
E 1	Purpose of Charge
The Usage Charge is payable by Scheduling Coordinators who schedule Energy across Congested Inter-Zonal Interfaces pursuant to Section 7.2.5 of the ISO Tariff.  Scheduling Coordinators who counter-schedule across Congested Inter-Zonal Interfaces are entitled to Usage Charge Payments.  The right to schedule across a Congested Inter-Zonal Interface is determined through the ISO’s Congestion Management procedures.
The following categories of Payments and Charges are covered in this Appendix E:
(a)	Usage Charges payable by Scheduling Coordinators for Energy transfers scheduled across Congested Inter-Zonal Interfaces and which contribute to Congestion.
(b)	Usage Charge rebates payable to Scheduling Coordinators for Energy transfers scheduled across Congested Inter-Zonal Interfaces and which contribute to relieving Congestion.
Credits of net Usage Charge revenues to Participating TOs.
(d)	Debits of net Usage Charge revenues to Participating TOs.
(e)	Rebates of Usage Charge to Scheduling Coordinators as set out in E 2.3.3.
E 2	Fundamental Formulae
E 2.1	ISO Usage Charges on Scheduling Coordinators
Each Scheduling Coordinator j whose Final Schedule includes the transfer of Energy scheduled across one or more Congested Inter-Zonal Interfaces  shall (save to the extent that the transfer involves the use of transmission capacity represented by Existing Rights and/or Non-Converted Rights) pay, or be paid, Usage Charges in Trading Interval t calculated in accordance with the following formulae:
In the Day-Ahead Market:

In the Hour-Ahead Market:

E. 2.2	Payments of Usage Charges to Scheduling Coordinators
Each Scheduling Coordinator j whose Final Schedule includes the transfer of Energy from one Zone to another in a direction opposite that of Congestion  shall (save to the extent that the transfer involves the use of transmission capacity represented by Existing Rights and/or Non-Converted Rights) receive a Usage Charge payment from the ISO calculated in accordance with the formulae described in section E2.1.
E 2.3	ISO Credits and Debits to Transmission Owners of Net Usage Charge Revenues
E 2.3.1	Day-Ahead Market
The ISO will pay to the Participating TOn in respect of the Transmission Revenue Balancing Account (being the owner, or part-owner, of a Congested Inter-Zonal Interface) its share of the total net Usage Charge revenue for Trading Interval t in the Day Ahead Market in accordance with the following formula:

E 2.3.2	Hour-Ahead Market
The ISO will pay to the Participating TOn (being the owner, or part owner, of a Congested Inter-Zonal Interface) in respect of its Transmission Revenue Balancing Account, for Trading Interval t its share of the total net Usage Charge revenue in accordance with the following formula:

Under normal operating conditions, (Lyth - Lytd) is positive and Participating TOs will receive a refund on the net Usage Charge for the relevant Trading Interval t in the Hour-Ahead Market.
E 2.3.3	Debits to Participating TOs and Rebates to Scheduling Coordinators
If, after the close of the Day-Ahead Market, Participating TOs instruct the ISO to reduce interface limits based on operating conditions or an unscheduled transmission outage occurs and as a result of  either of those events, Congestion is increased and Available Transfer Capacity is decreased in the Inter-Zonal Interface in the Hour-Ahead Market, the (Lyth - Lytd) will be negative. In this case Participating TOs will be charged for the relevant Trading Interval t in the Hour-Ahead Market and such charge will be apportioned to those Scheduling Coordinators whose Final Day-Ahead Schedules were reduced.
E 3	Meaning of terms of formulae
E 3.1	UCjtd 	($)
The Usage Charge payable by or to Scheduling Coordinator j for the relevant Trading Interval t in the Day-Ahead Market.
E 3.2 	UCjth – $
The Usage Charge payable by or to Scheduling Coordinator j for Trading Interval t in the Hour-Ahead Market.
E3.3	NetZoneImpjtxd 	(MWh)
The net Zonal import scheduled by Scheduling Coordinator j in Zone x for the relevant Trading Interval t in the Day-Ahead Market.  For Zones internal to the ISO Control Area, net Zonal import equals scheduled Demand minus scheduled Generation plus transfers. For zones external to the ISO Control Area (i.e., for Scheduling Points), net zonal import equals scheduled imports (i.e., out of the ISO Control Area) minus scheduled exports (i.e., into the ISO Control Area).
E 3.4	NetZoneImpjtxh 	(MWh)
The net zonal import scheduled by the Scheduling Coordinator j in Zone x for the relevant Trading Interval t in the Hour-Ahead Market.  For Zones internal to the ISO Control Area, net Zonal import equals scheduled Demand minus scheduled Generation plus transfers. For zones external to the ISO Control Area (i.e. for Scheduling Points), net zonal import equals scheduled imports (i.e., out of the ISO Control Area) minus scheduled exports (i.e. into the ISO Control Area).
E 3.5	dxt 	($/MWh)
The reference Zonal marginal price for Zone x  for the relevant Trading Interval t in the Day-Ahead Market, as calculated by the ISO’s Congestion Management computer optimization algorithm.
E 3.6	hxt 	($/MWh)
The reference Zonal marginal price for Zone x  for the relevant Trading Interval t in the Hour-Ahead Market, as calculated by the ISO’s Congestion Management computer optimization algorithm.
E 3.7	PayUCTOntd	($)
The amount calculated by the ISO to be paid to or by the Participating TOn (in respect of its Transmission Revenue Balancing Account) for the relevant Trading Interval t in the Day-Ahead Market.
E 3.7.1	PayUCTOnth 	($)
The amount calculated by the ISO to be paid to the Participating TOn (in respect of its Transmission Revenue Balancing Account) for the relevant Trading Interval t in the Hour-Ahead Market.
E 3.8	ytd	($/MW)
The Day-Ahead Congestion price for (shadow price)  at Inter-Zonal Interface y for Trading Interval t.  This price is calculated by the ISO’s Congestion Management computer optimization algorithm.
E 3.8.1	yth	($/MW)
The Hour-Ahead Congestion price (shadow price) at Inter-Zonal Interface y for Trading Interval t. This price is calculated by the ISO’s Congestion Management computer optimization algorithm.
E 3.9	Kyn	(%)
The percentage ownership by Participating TOn of the Congested Inter-Zonal Interface y.
E 3.10	Lytd	(MW)
The total loading of Inter-Zonal Interface y for Trading Interval t in the Day-Ahead as calculated by the ISO’s Congestion Management optimization algorithm.
E 3.11	Lyth	(MW)
The total loading of Inter-Zonal Interface y for Trading Interval t in the Hour-Ahead as calculated by the ISO’s Congestion Management optimization algorithm.
VIII.  WHEELING ACCESS CHARGES
Recent software testing and applications review has uncovered a major variance in software performance from the ISO’s system design.  Specifically, the ISO Settlements software calculates and allocates the Wheeling Access Charges using a methodology that is different from the methodology used in the ISO Tariff.
This variance was only recently discovered.  It is not possible to implement a change to the ISO software in time for it to be effective as of the ISO Operations Date.  The only options are to delay the ISO Operations Date or attempt a manual work-around.  This issue was presented to the Grid Reliability and Operations Committee (the "Committee") at its meeting on February  23, 1998.  The Committee was informed of the variance and the expected time to implement the correction.  ISO management requested authorization to prepare and file necessary ISO Tariff amendments to reflect the suspension of charges and any other temporary amendments to the ISO Tariff required to reflect actual functionality, pending correction of the software variance.  The Committee recommended and the Board authorized, at the February 24, 1998 meeting, the filing of necessary amendments, as contained in this section.
Although this issue was only identified recently, management has been able to identify means to calculate Wheeling Access Charges manually.  But absent an ISO Tariff change, the ISO will not have sufficient means to obtain information about Wheeling transactions at Bulk Supply Points or other points of interconnection between the ISO Controlled Grid and the transmission system of a Non-Participating TO to make the manual calculations.
Accordingly, the ISO proposes to obtain scheduling information for such transactions from the relevant Scheduling Coordinators and settle Wheeling charges and payments for such transactions on the basis of the information received.  This requires adding a new Section 7.1.4.4 to the ISO Tariff that obligates Scheduling Coordinators to provide the ISO with information on Wheeling Out or Wheeling Through transactions.  The ISO will use such information to settle Wheeling Access charges until the software variance is corrected.
The ISO proposes an automatic termination provision for Section 7.1.4.4 of the ISO Tariff with seven (7) days notice posted on the WEnet.  This termination provision is set out in Sections 7.1.4.4.1, 7.1.4.4.2 and 7.1.4.4.3 of the ISO Tariff.  This automatic termination is necessary to eliminate at the earliest possible time the additional burden being placed on Scheduling Coordinators until the ISO software variance is corrected.
ISO Tariff amendment
Add a new Section 7.1.4.4 to the ISO Tariff as follows:
7.1.4.4 	Information Required from Scheduling Coordinators.  Scheduling Coordinators that schedule Wheeling Out or Wheeling Through transactions to a Bulk Supply Point, or other point of interconnection between the ISO Controlled Grid and the transmission system of a Non-Participating TO, that are located within the ISO Control Area, shall provide the ISO, within 5 days from the end of the calendar month to which the relevant Trading Day relates, details of such transactions scheduled by them (other than transactions scheduled pursuant to Existing Contracts or Existing Control Agreements) sorted by Bulk Supply Point or point of interconnection for each Settlement Period (including kWh scheduled). The ISO shall use such information, which may be subject to review by the ISO, to settle Wheeling Access Charges and payments.  The ISO shall publish a list of the Bulk Supply Points or interconnection points to which this Section 7.1.4.4 applies together with details of the electronic form and procedure to be used by Scheduling Coordinators to submit the required information on the ISO “Home Page”.
7.1.4.4.1	Application.
Notwithstanding any other provision in this Tariff, including the ISO Protocols, the temporary simplification measure specified in this Section 7.1.4.4 shall have effect until discontinued by a Notice of Full-Scale Operations issued by the Chief Executive of the ISO.
7.1.4.4.2	Notice of Full-Scale Operations.
When the Chief Executive Officer of the ISO determines that the ISO is capable of implementing this Tariff, including the ISO Protocols, without modification in accordance with a temporary simplification measure specified in this Section 7.1.4.4, he shall issue a notice (“Notice of Full Scale Operations”) and shall specify the relevant temporary simplification measure and the date on which it will permanently cease to apply, which date shall be not less than seven (7) days after the Notice of Full-Scale Operations is issued.
7.1.4.4.3	A Notice of Full-Scale Operations shall be issued when it is posted on the ISO Internet “Home Page”, at http://www.caiso.com or such other internet address as the ISO may publish from time to time.
IX.  Default Usage ChaRge
The ISO Tariff requires a default Usage Charge to be applied in the event that the Adjustment Bids received by the ISO are insufficient to alleviate all Inter-Zonal Congestion.  Specifically, Section 7.3.1.3 of the ISO Tariff states: 
Default Usage Charge.  If inadequate or unusable Adjustment Bids have been submitted to the ISO to enable the ISO’s Congestion Management to schedule Inter-Zonal Interface capacity on an economic basis, then the ISO will assume a decremental bid of zero 
and an incremental bid equal to the highest Hourly Ex Post Price for the Zones on either side of the Inter-Zonal Interface for the relevant Settlement Period.

The software cannot, however, calculate the default Usage Charge as the Tariff contemplates.  Rather, the software currently specifies that the default Usage Charges on interfaces with residual Congestion are derived from an assumed decremental bid of zero and an assumed incremental bid that is the maximum of the previous day’s prices in the Imbalance Market.
The ISO considered modifying the Tariff to conform to the software.  However, a gaming concern has been identified regarding the design of Congestion Management with respect to the PX procedure for establishing Zonal Market Clearing Prices.  The problem occurs if there are insufficient Adjustment Bids to enable the ISO to clear Inter-Zonal Congestion.
The example below will illustrate the problem.
In the example, the Day-Ahead PX Market Clearing Price is initially set at $25.  Generator #1 and #2 each are selected to run in the Day-Ahead Energy auction at 1000MW, and neither submits Adjustment Bids.  Generator #3 is a 300MW Unit that is selected for 100MW Energy output, and has submitted Adjustment Bids as indicated.  The default Usage Charge is the previous Trading Day’s highest Imbalance Energy Market Clearing Price of $30 and is entered in the program prior to execution.  When Congestion Management runs, it will exercise both the Adjustment Bids for Generator #3 and raise Generator #3 output to 200MW.
This is not sufficient to relieve Congestion.  Therefore, the program will allocate additional reductions pro rata and produce the final schedules listed above.  The default Usage Charge will be set at $30.
The problem occurs as the PX attempts to set Zonal Market Clearing Prices based on the ISO default Usage Charge.  By definition, the PX Zonal prices must differ by the amount of the Usage Charge.  This could mean that the Market Clearing Price in Zone A is $0/MWh and the Price in Zone B is $30/MWh.  But Generator #3 had an Adjustment Bid of $200.  The PX must therefore raise the Zonal price in Zone B to $200.  This means by definition that the Zonal price in Zone A must now be $30 less or $170.  Essentially, this will provide enormous incentive for Generators #1 and #2 never to submit Adjustment Bids, because periodically, they will receive a windfall based upon the artificially high PX Market Clearing Price.
Many gaming scenarios could be demonstrated in addition to the problem outlined here.  This problem has already surfaced during testing, and could be present immediately at the ISO Operations Date.  The potential economic consequences are significant as can be calculated from the example above.
In addition to the potential for gaming, the ISO is concerned about the adverse effect on reliable operations.  System security and stability require prices sufficient to assure that adequate resources are attracted to the imbalance market.
This issue, the potential for gaming it creates, and the need for corrective action was first discussed with the Executive Committee of the Board at a special teleconference on February 17, 1998 and more extensively at the Grid Reliability and Operations Committee meeting February 23.  From February 17 through the end of the month, numerous discussions were held with Scheduling Coordinators to determine how to minimize the gaming and reliability risks while at the same time limiting the adverse economic impacts on Scheduling Coordinators who are unable to submit Adjustment Bids to avoid Usage Charges.  At the February 24 Board meeting, the Board directed management to file a Tariff amendment providing that the ISO would set the default Usage Charge at a price no higher than $500/MWh and that management would, in consultation with the Scheduling Coordinators and the ISO’s economic consultants, set the default Usage Charge.  Based on those discussions, the ISO is proposing two related changes as follows:
First, as noted, the ISO proposes to amend the ISO Tariff to set default Usage Charges initially at $250/MWh.  The ISO will retain the ability to move the figure incrementally or decrementally, but no higher than $500/MWh, by giving seven days’ notice published on the WEnet and the ISO’s “Home Page."  Necessarily this price is initially a matter of judgment, but after start-up further studies can be used to justify a lower or higher price if the evidence from accumulated experience warrants a change. The ISO is committed to reduce this price if there is reasonable assurance that the Day-Ahead Market for Adjustment Bids works smoothly and that a lower price suffices.  (Conversely, if the market appears to be clearing near the selected price, the ISO needs the flexibility to increase the default Usage Charge.)
Second, the ISO will partially address Scheduling Coordinator concerns by permitting Adjustment Bids on all loads, not just those which can be physically curtailed.  This second amendment allows Scheduling Coordinators relying solely on Inter-Scheduling Coordinator Trades to avoid the default Usage Charge by relying on the Imbalance Market. 
ISO Tariff Amendments
7.3.1.3	Default Usage Charge.  If inadequate or unusable Adjustment Bids have been submitted to the ISO to enable the ISO’s Congestion Management to schedule Inter-Zonal Interface capacity on an economic basis, then the ISO will assume a decremental bid of zero and an incremental bid equal to $250/MWh for the relevant Settlement Period.  The ISO may change the default Usage Charge either incrementally or decrementally at any time by giving seven days’ notice published on WEnet and the ISO’s “Home Page”, but will not set a default Usage Charge lower than $200/MWh or higher than $500/MWh.
Scheduling Protocol Amendments
SP 10.3	Congestion Management Pricing
(b)	The ISO will determine the prices for the use of Congested Inter-Zonal Interfaces using the Adjustment Bids.  The ISO will collect Usage Charges from SCs for their Scheduled use of Congested Inter-Zonal Interfaces.  If Adjustment Bids are exhausted and Schedules are adjusted pro rata, the ISO will apply a default Usage Charge set at $250.  The ISO may change the default Usage Charge either incrementally or decrementally at any time by giving seven days’ notice published on WEnet and the ISO’s “Home Page”, but will not set a default Usage Charge lower than $200/MWh or higher than $500/MWh.
X.  Generation Meter Multiplier will not be published 
with the final hour-ahead schedules
In November, several ISO Tariff provisions were removed or modified to reflect limitations in the software’s ability to produce Generation Meter Multipliers calculations.  Inadvertently, one of the provisions intended for deletion remained in the ISO Tariff.  This provision, set forth in ISO Tariff Section 2.2.13.3.1.5, states that the ISO is to provide Scheduling Coordinators with “Final Generation Meter Multipliers for each Generation location and Scheduling Point in accordance with Section 7.4.2.”  This amendment, consistent with the ISO’s previous deletions, removes that remaining incorrect reference to the ISO’s schedule for providing GMMs.
Accordingly, Section 2.2.13.3.1.5 to the ISO Tariff is revised as follows:
2.2.13.3.1.5	[Not Used]