Exhibit A
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION

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

AMENDMENT NO. 2

SUBMITTED ON
FEBRUARY 25, 1998

New Definition for the ISO Control Area and New Definition
“Existing Control Agreements”

The ISO is filing amendments to a number of sections of the ISO Tariff, including the ISO Protocols and the pro forma Scheduling Coordinator Agreement, to clarify the distinction between the “ISO Controlled Grid” and the “ISO Control Area.”  These terms are not interchangeable, yet they are not precisely distinguished in the ISO Tariff.  In some instances, the terms are either not applied appropriately or are ambiguous as to applicability.  The ISO therefore proposes the addition of  new defined terms in the ISO Tariff – “ISO Control Area” and “Existing Control Agreement” – along with certain consequential amendments to the ISO Tariff, including the ISO Protocols and pro forma Scheduling Coordinator Agreement.
These amendments are designed to eliminate any ambiguities and misunderstandings that may presently exist within the ISO Tariff and ISO Protocols as to the meaning and applicability of the terms “ISO Controlled Grid” and “ISO Control Area.”  This amendment will resolve several areas of misunderstanding regarding the obligations of Scheduling Coordinators with respect to schedules for transactions into, out of, within, or through the ISO Control Area, or across transmission facilities forming part of the ISO Controlled Grid by virtue of Entitlements but located outside the ISO Control Area.
A.	Definition of “ISO Control Area”

The ISO Tariff presently includes a generic definition for “Control Area” and it also, of course, contains a definition for “ISO.”  The problem arises when these two terms are used together to refer to the “ISO Control Area,” as an “implicitly defined” term.
The ISO Control Area is unlike any other Control Area in the North American Electric Reliability Council (“NERC”), in terms of the relationships that will exist between Scheduling Coordinators, the ISO, and other Control Areas.  The design of the California forward markets for Energy and Ancillary Services, and the reliable operation of the ISO Control Area in real-time, is founded on the premise that Generation and Demand within the ISO Control Area, as well as all interties with neighboring Control Areas, are to be scheduled and/or bid with the ISO through Scheduling Coordinators.
There is a further complication.  The ISO Tariff repeatedly uses the term “ISO Controlled Grid,” even in instances where the “ISO Control Area” is intended.  The ISO Controlled Grid is a subset of the actual systems that are under ISO control as the Control Area operator, and for which the ISO has reliability responsibilities pursuant to the NERC and WSCC requirements.  There are numerous entities – such as municipal utilities – which own transmission facilities within the ISO Control Area but have not yet indicated an intention to become parties to the Transmission Control Agreement.  The ISO’s responsibilities as Control Area operator, including arranging the provision of Regulation, Operating Reserves, Replacement Reserves, and other Reliability services, will inevitably extend to these entities.
Moreover, long established scheduling practices dictate that all interchange schedules between Control Areas must be submitted to and coordinated by the operators of the Control Areas (both inside and outside of California).  All Scheduling Coordinators will, therefore, require the assistance of the California ISO to schedule the use of interchange transmission capacity into, out of, and through the ISO Control Area.  Without a Scheduling Coordinator to submit the scheduled uses of transmission capacity into, out of, or through the ISO Control Area, whether across the ISO Controlled Grid (including transmission facilities forming part of the ISO Controlled Grid by virtue of Entitlements), or other facilities owned by others within the ISO Control Area, the power simply cannot be scheduled with the ISO and will not flow in accordance with NERC and WSCC accepted scheduling practices.
In other words, the implicit definition of “ISO Control Area” in the ISO Tariff does not reflect the unique features of the California structure.  To meet these concerns, the ISO proposes to add a new definition to the ISO Tariff for “ISO Control Area,” as follows:
The ISO electric power system (initially comprising the electric power systems previously operated as Control Areas by PG&E, SCE, and SDG&E, including, but not limited to, the facilities and Entitlements which represent the ISO Controlled Grid), for which the ISO has reliability responsibilities pursuant to NERC and WSCC requirements.  The ISO’s AGC scheme applies to this system, in order to:

i)	match, at all times, the power output of Scheduling Coordinators' Generating Units within the ISO electric power system, plus the Energy imported by Scheduling Coordinators from entities located beyond the ISO's points of interchange with adjoining Control Areas, minus Energy exported by Scheduling Coordinators to entities located beyond the ISO's points of interchange with adjoining Control Areas, with Scheduling Coordinators' Demand within the ISO electric power system;

ii)	maintain scheduled interchange with other Control Areas, within the limits of Good Utility Practice;

iii)	maintain the frequency of the ISO electric power system within reasonable limits in accordance with Good Utility Practice; and

iv)	provide sufficient generating capacity to maintain Operating Reserves in accordance with Good Utility Practice.

This proposed definition reflects the fact that the ISO Control Area encompasses all of the electric power system facilities within the electrical boundaries defined by the points of interchange with adjoining Control Areas, including, as a subset, those facilities and Entitlements that have been transferred to the control of the ISO as “ISO Controlled Grid” facilities.  It clarifies the important distinction between the “ISO Control Area” and the “ISO Controlled Grid.” As the operator of the ISO Control Area, the ISO will be responsible for maintaining the safe and reliable operation of the electric power system that extends beyond the subset of ISO Controlled Grid facilities and Entitlements.
B.	Consequential Amendments

As noted above, the lack of an explicit definition for “ISO Control Area” and the incorrect use of “ISO Controlled Grid” when the references should have been to the “ISO Control Area,” has led to certain ambiguities in the ISO Tariff.  The ISO therefore proposes a number of consequential amendments to the ISO Tariff with respect to the usage of the new term “ISO Control Area” and the term “ISO Controlled Grid.”  The proposed amendments, as set out in the attached document, should serve to convey, more properly, the sense of several important concepts presently set forth in the ISO Tariff and at the heart of the ISO’s system structure.
1.	Compensation for Control Area Services
A significant consequential amendment is found in Section 8.3 of the ISO Tariff, relating to liability for the ISO’s Grid Management Charge (“GMC”).  The ISO respectfully submits that this clarification is at the heart of the protests the ISO expects to this filing.  By utilizing the new term “ISO Control Area” as well as “ISO Controlled Grid” in Section 8.3, it will be clear that the GMC is payable by all of the parties that benefit from the ISO's exercise of its responsibilities as the operator of the ISO Control Area.  These responsibilities include the safe and reliable operation of the entire ISO Control Area, not just supporting the scheduling and/or bidding of Energy and Ancillary Services of all Scheduling Coordinators.
Such responsibilities, and the associated costs borne by the ISO, derive not only from the ISO's control of a subset of facilities and Entitlements transferred to it by Participating Transmission Owners (the “ISO Controlled Grid”) but, more broadly, from Scheduling Coordinators' scheduling activities within and beyond the ISO Control Area, including scheduling activities pursuant to Existing Control Agreements, Existing Operating Agreements and Existing Contracts.  Control Area services result in costs to the ISO and significant benefits to users – benefits that will be enhanced by the consolidation of the three utilities’ Control Areas into a single Control Area covering virtually the entire state of California.
For example, one of the ISO's primary responsibilities in operating the ISO Control Area is to ensure an adequate supply of Operating Reserves.  As the largest Control Area to be operating in the WSCC, the consequences of not adequately identifying, and having available, the necessary supply of Operating Reserves at all times can adversely affect the reliable operation of both the ISO Control Area and adjoining Control Areas throughout the WSCC. 
Operating Reserves can either be self-provided or purchased from the ISO through its Ancillary Services auction.  In accordance with the ISO Tariff, and consistent with the ISO's role as the ISO Control Area operator, all Ancillary Services, whether self-provided or purchased from the ISO, must be identified for, and available to, the ISO as resources that can be called upon in real-time to meet ISO Control Area requirements.  As such, any and all Ancillary Services necessary to satisfy minimum operating reliability criteria will be processed and evaluated by ISO personnel via the ISO's telecommunications and computing infrastructure.  Since the ISO does not own generation, it must rely wholly on the reserves that are self-provided or acquired via the auction process.
Costs for Ancillary Services purchased from the ISO auction are included in the statement sent to the Scheduling Coordinator.  Without a requirement that all Schedules be submitted in the requisite form through a Scheduling Coordinator, the ISO would not have the information it needs to perform its Control Area operator responsibilities nor the necessary contractual relationship by which to charge for Ancillary Services.  Specifically, unless an entity acts through a Scheduling Coordinator, should such an entity fail to self-provide Ancillary Services or supply its share of Imbalance Energy, there would be no mechanism to capture those uses in the billing and settlement system, nor a contract path by which to seek payment.  Simply put – the ISO is not structured to deal with any entity other than through a Scheduling Coordinator with whom it has a contractual relationship, lines of communication, and mechanisms to bill and collect payment for use of services.
2.	Existing Control Agreements
As mentioned above, the Control Areas now operated by the Participating Transmission Owners include transmission facilities owned by third parties who are not currently proposing to transfer Operational Control of those facilities to the ISO and thereby become Participating Transmission Owners themselves.  The Participating Transmission Owners act as Control Area operators in relation to these facilities under various contractual arrangements.  In order to ensure that the ISO is able to fulfill its function as the Control Area operator for the new combined ISO Control Area, it is necessary that the scheduling and other Control Area functions currently exercised by the Participating Transmission Owners in respect of third parties' facilities is transferred to the ISO.
A new definition of “Existing Control Agreement” has been added to the Tariff to describe these arrangements between Participating Transmission Owners and third party owners of transmission facilities in their Control Areas.  Under a new Section 3.3 of the Tariff, a Participating Transmission Owner that is a party to an Existing Control Agreement would be obliged to schedule (unless otherwise scheduled) all Energy and Ancillary Services on such transmission facilities with the ISO.  Under Section 3.3 of the Tariff the ISO may also request the Participating Transmission Owner to exercise its rights under the agreement as directed by the ISO to enable the ISO to fulfill its functions as Control Area operator.  To allow the Existing Control Agreement to be implemented, the ISO proposes to amend the ISO Tariff with several new provisions with a commitment which is similar in spirit to the ISO’s obligations to honor Existing Contracts brought by Participating Transmission Owners.
3.	Amendment to Pro-Forma Agreement
A few minor amendments are also needed to the pro forma Scheduling Coordinator Agreement set out in Appendix B of the Tariff consequent on the amendments to the body of the Tariff.  These involve changing references to “ISO Controlled Grid” to read “ISO Control Area.” These changes clarify that the scheduling of all Energy and Ancillary Services in the ISO Control Area is subject to the provisions of the ISO Tariff and Protocols.
Accordingly, the following Sections of the ISO Tariff and certain ISO Protocols are revised as follows.
ISO TARIFF AMENDMENTS
2.	ISO OPERATIONS.
2.1	Access to the ISO Controlled Grid.
2.1.1	Open Access.
The ISO shall, subject to Sections 2.1.2 and 2.1.3, provide to all Eligible Customers open and non-discriminatory access on the ISO Controlled Grid regardless of their connections to the ISO Controlled Grid in accordance with the terms of this ISO Tariff including, in particular, the applicable procedures for scheduling and Congestion Management.  Energy and Ancillary Services may be transmitted into, out of, within, or through the ISO Control Area  or across transmission facilities forming part of the ISO Controlled Grid by virtue of Entitlements but located outside the ISO Control Area only if scheduled by a Scheduling Coordinator.  An Eligible Customer may not be represented by more than one Scheduling Coordinator.  A Scheduling Coordinator must ensure that each Eligible Customer which it represents has all appropriate licenses or authorizations from the Local Regulatory Authority, FERC or any other regulatory body.
2.2	Scheduling.
2.2.1	Scheduling Responsibilities and Obligations.
The provisions of this Section 2.2 shall govern Congestion Management and the ISO’s scheduling of Energy and Ancillary Services into, out of, within, or through the ISO Control Area, or across transmission facilities forming part of the ISO Controlled Grid by virtue of Entitlements but located outside the ISO Control Area.  Nothing in this ISO Tariff is intended to permit or require the violation of Federal or California law concerning hydro-generation and Dispatch, including but not limited to fish release requirements, minimum and maximum dam reservoir levels for flood control purposes, and in-stream flow levels.  In carrying out its functions, the ISO will comply with and will have the necessary authority to give instructions to Participating TOs and Market Participants to enable it to comply with requirements of environmental legislation and environmental agencies having authority over the ISO in relation to Environmental Dispatch and will expect that submitted Schedules will support compliance with the requirements of environmental legislation and environmental agencies having authority over Generators in relation to Environmental Dispatch.  In contracting for Ancillary Services and Imbalance Energy the ISO will not act as principal but as agent for and on behalf of the relevant Scheduling Coordinators.
2.2.6.8	Annual and Weekly Forecasts.  Submitting to the ISO the forecasted weekly peak Demand in the ISO Control Area and the forecasted Generation capacity.  The forecasts shall cover a period of 12 months on a rolling basis;
2.2.7.2	Submitting Balanced Schedules.  A Scheduling Coordinator shall submit to the ISO only Balanced Schedules in the Day-Ahead Market and the Hour-Ahead Market.  A Schedule shall be treated as a Balanced Schedule when aggregate Generation, Inter-Scheduling Coordinator Trades (whether purchases or sales), and imports or exports to or from external Control Areas adjusted for Transmissions Losses as appropriate, equals aggregate forecast Demand with respect to all entities for which the Scheduling Coordinator schedules in each Zone. If a Scheduling Coordinator submits a Schedule that is not a Balanced Schedule, the ISO shall reject that Schedule provided that Scheduling Coordinators shall be able to validate their Schedules prior to the deadline for submission to the ISO.
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 notifies a Scheduling Coordinator that there will be no Congestion in the ISO Control Area, the Preferred Schedule shall become that Scheduling Coordinator’s Final Schedule.
2.2.8.4	Final Schedules.  If the ISO notifies a Scheduling Coordinator that there will be no Congestion in the ISO Control Area, the Revised Schedule shall become that Scheduling Coordinator's Final Schedule.  If no Scheduling Coordinator submits any changes to the Suggested Adjusted Schedules, all of the Suggested Adjusted Schedules shall become the Final Schedules.  The Final Schedules shall serve as the basis for Settlement between the ISO and each Scheduling Coordinator.
2.2.12.8.1	Revised Schedules Become Final Day-Ahead Schedules.  If the ISO identifies no Congestion in the ISO Control Area subsequent to receiving the Revised Schedules, the Revised Schedules and any unamended Preferred Schedules shall become Final Day-Ahead Schedules and the ISO shall notify Scheduling Coordinators accordingly.
2.2.13.2.1	Preferred Schedules Become Final Hour-Ahead Schedules.  If the ISO identifies no Congestion  in the ISO Control Area subsequent to receiving the Preferred Schedule, the Preferred Schedules shall become Final Hour-Ahead Schedules and the ISO shall notify Scheduling Coordinators accordingly.
2.3	System Operations under Normal and Emergency Operating Conditions.
2.3.1	ISO Control Center Operations.
2.3.1.1	ISO Control Center.
2.3.1.1.1	Establish ISO Control Center.  The ISO shall establish a WSCC approved Control Area and control center to direct the operation of all facilities under ISO jurisdiction as Control Area operator, including other transmission facilities in the ISO Control Area which are the subject of Existing Control Agreements or Existing Operating Agreements, Reliability Must-Run Units and Generating Units providing Energy or Ancillary Services.
2.3.1.1.2	Establish Back-up Control Facility.  The ISO shall establish back-up control facilities remote from the ISO Control Center sufficient to enable the ISO to continue to direct the operation of facilities under ISO jurisdiction as Control Area operator, including transmission facilities in the ISO Control Area which are the subject of Existing Control Agreements or Existing Operating Agreements, Reliability Must-Run Units and Generating Units providing Energy or Ancillary Services in the event of the ISO Control Center becoming inoperable.
2.3.1.1.3	ISO Control Center Authorities.  The ISO shall have full authority, subject to Section 2.3.1.2 to direct the operation of the facilities referred to in Section 2.3.1.1.2 including (without limitation), to:
(a)	direct the physical operation of the facilities under ISO jurisdiction as Control Area operator, including (without limitation) ISO Controlled Grid circuit breakers, switches, voltage control equipment, protective relays, metering, and Load Shedding equipment and other transmission facilities in the ISO Control Area which are the subject of Existing Control Agreements or Existing Operating Agreements;
(b)	commit and dispatch Reliability Must-Run Units;
(c)	order a change in operating status of auxiliary equipment required to control voltage or frequency;
(d)	take any action it considers to be necessary consistent with Good Utility Practice to protect against uncontrolled losses of Load or Generation and/or equipment damage resulting from unforeseen occurrences;
(e)	control the output of Generating Units that are selected to provide Ancillary Services and Imbalance Energy;
(f)	dispatch Loads through direct Load control or other means at the ISO’s discretion that are curtailable as an Ancillary Service; and
(g)	procure Supplemental Energy.
2.3.1.1.4	Coordination and Approval for Outages.  The ISO shall have authority to coordinate and approve Outages and returns to service of all facilities under ISO jurisdiction as Control Area operator, including transmission facilities in the ISO Control Area which are the subject of Existing Control Agreements or Existing Operating Agreements, and Reliability Must-Run Units in accordance with Section 2.3.3.
2.3.1.1.5	Responsibility for Authorized Work on Facilities.  The ISO shall have authority to approve requests by Participating TOs and Existing Operating Entities, to work on all energized transmission equipment under ISO jurisdiction as Control Area operator, including transmission facilities in the ISO Control Area which are the subject of Existing Control Agreements or Existing Operating Agreements.
2.3.1.1.6	The ISO shall be the WSCC security coordinator for the California sub-region of the WSCC, as designated by WSCC.
2.3.1.2	Market Participant Responsibilities.
2.3.1.3	Operating Reliability Criteria.
2.3.1.3.1	The ISO shall exercise its authority as Control Area operator and its Operational Control over the ISO Controlled Grid to meet planning and Operating Reserve criteria no less stringent than those established by WSCC and NERC as those standards may be modified from time to time, and Local Reliability Criteria that are in existence on the ISO Operations Date and have been submitted to the ISO by each Participating TO pursuant to Section 2.2.1(v) of the TCA.  All Market Participants and the ISO shall comply with the ISO reliability criteria, standards, and procedures.
2.3.2.2	Emergency Procedures.  In the event of a System Emergency, the ISO shall take such action as it considers necessary to preserve or restore stable operation of the ISO Control Area .  The ISO shall act in accordance with Good Utility Practice to preserve or restore reliable, safe and efficient service as quickly as reasonably practicable.  The ISO shall keep system operators in adjacent Control Areas informed as to the nature and extent of the System Emergency in accordance with WSCC procedures and, where practicable, shall additionally keep the Market Participants within the ISO Control Area informed.
2.3.2.3.1	The ISO will not intervene in the operation of the Day-Ahead Market unless there has been a total or major collapse of the ISO Controlled Grid or ISO Control Area and the ISO is in the process of restoring it.
2.3.2.9	System Emergency Reports and Sanctions.
2.3.2.9.1	Review of Major Outages.  The ISO, with the cooperation of any affected UDC, Existing Operating Entity or Non-Participating TO which is party to an Existing Control Agreement, shall jointly perform a review following a major Outage that affects at least 10 percent of the Load served by the Distribution System of a UDC, Existing Operating Entity, or Non-Participating TO which is party to an Existing Control Agreement or any Outage that results in major damage to the ISO Controlled Grid or other portions of the ISO Control Area or to the health and safety of personnel.  The review shall address the cause of the Outage, the response time and effectiveness of emergency management efforts, and whether the operation, maintenance or scheduling practices of any Participating TOs, Eligible Customers, UDCs, Existing Operating Entities, or Non-Participating TOs which are party to an Existing Control Agreement or Participating Generators enhanced or undermined the ability of the ISO to maintain or restore service efficiently and in a timely manner.
2.3.3	Coordination of Outages and Maintenance.
2.3.3.1	ISO Outage Coordination Office.  The ISO Outage Coordination Office shall be established by the ISO and shall coordinate and approve Maintenance Outages of all facilities under ISO jurisdiction as Control Area operator, including transmission facilities in the ISO Control Area which are the subject of Existing Control Agreements or Existing Operating Agreements, and Reliability Must-Run Units.  The ISO shall additionally coordinate and approve Outages required for new construction and for work on de-energized and live transmission facilities (e.g., relay maintenance or insulator washing) and associated equipment.
2.3.3.2	Requirement for Approval.  An Operator shall not take facilities under ISO jurisdiction as Control Area operator, including transmission facilities in the ISO Control Area which are the subject of Existing Control Agreements or Existing Operating Agreements, or Reliability Must-Run Units, out of service for the purposes of planned maintenance or for new construction or other work except as approved by the ISO Outage Coordination Office.
2.3.3.3	Requests for Outages in Real Time Operation.  Requests for Outages of facilities under ISO jurisdiction as Control Area operator, including transmission facilities in the ISO Control Area which are the subject of Existing Control Agreements or Existing Operating Agreements, and Reliability Must-Run Units, in real time operation shall be made by the Operator to the ISO Control Center.
2.3.3.5.1	The ISO Outage Coordination Office shall evaluate whether the requested Maintenance Outage or change to an Approved Maintenance Outage is likely to have a detrimental effect on the efficient use and reliable operation of facilities under ISO jurisdiction as Control Area operator, including transmission facilities in the ISO Control Area which are the subject of Existing Control Agreements or Existing Operating Agreements, or the facilities of a Connected Entity.
2.3.3.5.2	Where the ISO Outage Coordination Office reasonably determines that the requested Maintenance Outage or the requested change to an Approved Maintenance Outage, when evaluated together with existing Approved Maintenance Outages, is not likely to have a detrimental effect on the efficient use and reliable operation of facilities under ISO jurisdiction as Control Area operator, including transmission facilities in the ISO Control Area which are the subject of Existing Control Agreements or Existing Operating Agreements or the facilities of a Connected Entity, the ISO shall authorize the Maintenance Outage or change to the Approved Maintenance Outage, and shall so notify the requesting Operator and other entities who may be directly affected.
2.3.3.5.3	Where, in the reasonable opinion of the ISO Outage Coordination Office, the requested Maintenance Outage or requested change to an Approved Maintenance Outage is likely to have a detrimental effect on the efficient use and reliable operation of facilities under ISO jurisdiction as Control Area operator, including transmission facilities in the ISO Control Area which are the subject of Existing Control Agreements or Existing Operating Agreements or the facilities of a Connected Entity, the ISO Outage Coordination Office may reject the requested Maintenance Outage or requested change to Approved Maintenance Outage.  The determination of the ISO Outage Coordination Office shall be final and binding on the Operator.  If, within 14 days of having made its determination, the Operator requests the ISO Outage Coordination Office to provide reasons for its determination, it shall do so as soon as is reasonably practicable.  The ISO will give reasons for informational purposes only and without affecting in any way the finality or validity of the determination.
2.3.3.6	Maintenance Outage Requests by the ISO.  The ISO Outage Coordination Office may at any time request a Maintenance Outage or a change to an Approved Maintenance Outage from an Operator if, in the opinion of the ISO Outage Coordination Office, the requested Maintenance Outage or change is required to secure the efficient use and reliable operation of facilities under ISO jurisdiction as Control Area operator, including transmission facilities in the ISO Control Area which are the subject of Existing Control Agreements or Existing Operating Agreements or the facilities of a Connected Entity.
2.3.3.9.2	All notifications of Forced Outages shall be communicated to the ISO Control Center with as much notice as possible in order that the necessary security analysis and ISO Control Area assessments may be performed.  If prior notice of a Forced Outage cannot be given, the Operator shall notify the ISO of the Forced Outage immediately after it occurs.
2.3.3.10	Other Control Areas.  The ISO Outage Coordination Office shall make all reasonable efforts to coordinate Outages involving other Control Areas or affecting an intertie, import or export capability not under the Operational Control of the ISO to the extent that they may affect the reliability of the ISO Control Area.
2.3.4	Management of Overgeneration Conditions.
The ISO’s management of Overgeneration relates only to real time.  Overgeneration in real time will be mitigated by the ISO through the Imbalance Energy market and, to the extent that this is insufficient to resolve the problem, by directing each Scheduling Coordinator to reduce its Generation pro rata based on the product of the total required reduction in Generation and the ratio of its Demand to the total Demand in the ISO Control Area.
2.3.5.1.1	On an annual basis, the ISO shall prepare a forecast of weekly Generation capacity and weekly peak Demand in  the ISO Control Area.  This forecast shall cover a period of twelve months and be posted on the WEnet and the ISO may make the forecast available in other forms at the ISO's option.
2.3.5.1.3	If the forecast shows that the applicable WSCC/NERC Reliability Criteria cannot be met during peak Load periods, then the ISO shall facilitate the development of market mechanisms to bring the ISO Control Area during peak periods into compliance with the Applicable Reliability Criteria (or such more stringent criteria as the ISO may impose pursuant to Section 2.3.1.3.2).  The ISO shall solicit bids for Replacement Reserves in the form of Ancillary Services, short-term Generation supply contracts of up to one (1) year with Generators, and Load curtailment contracts giving the ISO the right to reduce the Loads of those parties that win the contracts when there is insufficient Generation capacity to satisfy those Loads in addition to all other Loads.  The curtailment contracts shall provide that the ISO's curtailment rights can only be exercised after all available Generation capacity has been fully utilized unless the exercise of such rights would allow the ISO to satisfy the Applicable Reliability Criteria at lower cost, and the curtailment rights shall not be exercised to stabilize or otherwise influence prices for power in the Energy markets.
2.4.3.4	Each Participating TO which is a party to an Existing Control Agreement will work with the ISO to develop operational protocols (which shall be based on existing protocols and procedures to the extent possible) which allow the ISO to perform its duties and obligations under this Tariff, including the Protocols.  The provisions of this Section 2.4.3 shall apply to Existing Control Agreements to the same extent as they apply to Existing Contracts.
2.4.4.3.1.2	The recipient of the transmission service under an Existing Contract that has converted its rights to ISO transmission service shall obtain all future transmission services within, into, out of, or through the ISO Control Area, or across transmission facilities forming part of the ISO Controlled Grid by virtue of Entitlements but located outside the ISO Control Area, using the ISO’s scheduling and operational procedures and ISO Protocols and the ISO Tariff and any applicable TO Tariff, provided that this provision shall not affect the rights, if any, of the contract parties to extend Existing Contracts.
2.4.4.6	ISO Treatment of Rights Under Existing Control Agreements
2.4.4.6.1	The ISO will have no role in interpreting Existing Control Agreements.  The parties to an Existing Control Agreement will, in the first instance, attempt jointly to agree on any operating instructions that will be submitted to the ISO by the Participating TO.  In the event that the parties to the Existing Control Agreement cannot agree upon the operating instructions submitted by the parties to the Existing Control Agreement, the dispute resolution provisions of the Existing Control Agreement, if applicable, shall be used to resolve the dispute; provided that, until the dispute is resolved, and unless the Existing Control Agreement specifies otherwise, the ISO shall implement the Participating TO’s operating instructions.
2.4.4.6.2	The ISO’s Schedules and Bids and Scheduling Protocols will accommodate the rights held by parties under Existing Control Agreements in the same manner in which Existing Rights and Non-Converted Rights are accommodated under Existing Contracts, so that the holders of rights under Existing Control Agreements will receive the same priorities (in scheduling, curtailment, assignment and other aspects of transmission system usage) to which they are entitled under their Existing Control Agreements.
2.4.4.6.3	Scheduling deadlines and operational procedures associated with rights under Existing Control Agreements will be honored by the ISO.
2.4.4.6.4.1	The holders of rights under Existing Control Agreements will not be responsible for paying Usage Charges related to those rights, nor will they be entitled to receive Usage Charge revenues related to those rights.
2.4.4.6.5	Other than any existing rights to such revenues under the Existing Control Agreements, the holders of rights under Existing Control Agreements will not be entitled to an allocation of revenues from Wheeling Out or Wheeling Through services, related to those rights.
2.4.4.6.6	The holders of rights under Existing Control Agreements shall continue to pay the providers of service under Existing Control Agreements at the rates provided in the associated Existing Control Agreements, as they may change from time to time under the terms of the Existing Control Agreements.
2.4.4.6.7	To the extent that Transmission Losses or Ancillary Service requirements under Existing Control Agreements are not the same as those under the ISO’s rules and protocols, the ISO will not charge or credit the Participating TO for any cost differences between the two, but will provide the parties to the Existing Control Agreements with details of its Transmission Losses and Ancillary Services calculations to enable them to determine whether the ISO’s calculations result in any associated shortfall or surplus and to enable the parties to the Existing Control Agreement to settle the differences bilaterally.
2.4.4.7	ISO Protocols Shall Accommodate Rights Under Existing Control Agreements
Under the ISO Schedules and Bids and Scheduling Protocols:
2.4.4.7.1	Existing scheduling rules, curtailment priorities and any other relevant terms and conditions associated with the scheduling and day-to-day implementation of transmission rights will be documented in sets of operating instructions provided to the ISO by the parties to the Existing Control Agreements.  The documentation of these operating instructions, and disputes related to the operating instructions, will be handled in accordance with the terms of Section 2.4.4.6.1.
2.4.4.7.2	The ISO shall coordinate the scheduling of rights under Existing Control Agreements with the scheduling of ISO transmission service, using the ISO’s Day-Ahead scheduling rules and protocols.  In doing so, the ISO shall subtract from the capacity that is available for the ISO to schedule in the ISO’s Day-Ahead scheduling process an appropriate amount of transmission capacity reflected the amount and nature of the rights under the Existing Control Agreements.
2.4.4.7.3	The ISO shall recognize that the obligations, terms or conditions of Existing Control Agreements may not be changed without the voluntary consent of all parties to the contract (unless such contract may be changed pursuant to any applicable dispute resolution provisions in the contract or pursuant to Section 205 or Section 206 of the FPA and the FERC’s Rules and Regulations or as otherwise provided by law).
2.4.4.8	Liability and Disputes Under Existing Control Agreements
2.4.4.8.1	The parties to Existing Control Agreements shall remain liable for their performance under the Existing Control Agreements.  The ISO shall be liable in accordance with the provisions of this ISO Tariff for any damage or injury caused by its non-compliance with the operating instructions submitted to it pursuant to Sections 2.4.3.4 and 2.4.4.6.
2.4.4.8.2	Unless specified otherwise, in the event that the dispute resolution mechanisms prescribed in an Existing Control Agreement, including all recourses legally available under the contract, cannot, in the first instance, result in a resolution of such a dispute, the ISO’s ADR Procedure will be used to resolve any disputes between the ISO and the Participating TO regarding any aspects of the implementation of Sections 2.4.3.4, 2.4.4.6, 2.4.4.7 or this Section 2.4.4.8, including the reasonableness of a Participating TO’s operating instructions or any other decision rules which the Participating TO may submit to the ISO as part of the operational protocols.  The rights-holder(s) under the Existing Control Agreement shall have standing to participate in the ISO ADR Procedure.2.5	Ancillary Services.
2.5.1	Scope.
The ISO shall be responsible for ensuring that there are sufficient Ancillary Services available to maintain the reliability of the ISO Control Area consistent with WSCC and NERC criteria.  The ISO's Ancillary Services requirements may be self provided by Scheduling Coordinators.  Those Ancillary Services which the ISO requires to be available but which are not being self provided will be competitively procured by the ISO from Scheduling Coordinators in the Day-Ahead Market, Hour-Ahead Market and in real time or by longer term contracts.  The ISO will manage both ISO procured and self provided Ancillary Services as part of the real time dispatch.  The ISO will calculate payments for Ancillary Services to Scheduling Coordinators and charge the cost to Scheduling Coordinators.
	For purposes of this ISO Tariff, Ancillary Services are:  (i) Regulation, (ii) Spinning Reserve, (iii) Non-Spinning Reserve, (iv) Replacement Reserve, (v) Voltage Support, and (vi) Black Start capability.  Bids for Non-Spinning Reserve and Replacement Reserve may be submitted by the Demand-side as well as by owners of Generation.  Identification of specific services in this ISO Tariff shall not preclude development of additional interconnected operation services over time.  The ISO and Market Participants will seek to develop additional categories of these unbundled services over time as the operation of the ISO Control Area matures.
2.5.2.1	Determination of Ancillary Service Standards.  The ISO shall set the required standard for each Ancillary Service necessary to maintain the reliable operation of the ISO Control Area.  Ancillary Services standards shall be based on WSCC Minimum Operating Reliability Criteria (MORC) and ISO Control Area reliability requirements.  The ISO Technical Advisory Committee, in conjunction with the relevant reliability council (WSCC), shall develop these Ancillary Services standards to determine reasonableness, cost effectiveness, and adherence to national and WSCC standards.  The standards developed by the ISO shall be used as a basis for determining the quantity and type of each Ancillary Service which the ISO requires to be available.
2.5.2.2	Time-frame For Revising Ancillary Service Standards.  The ISO Technical Advisory Committee shall periodically undertake a review of the ISO Control Area operation to determine any revision to the Ancillary Services standards to be used in the ISO Control Area.  At a minimum the ISO Technical Advisory Committee shall conduct such reviews to accommodate revisions to WSCC and NERC standards.  The ISO may adjust the Ancillary Services standards temporarily to take into account, among other things variations in system conditions, real time dispatch constraints, contingencies, and voltage and dynamic stability assessments.
2.5.3.4	Voltage Support.
The ISO shall determine on an hourly basis for each day the quantity and location of Voltage Support required to maintain voltage levels and reactive margins within WSCC and NERC criteria using a power flow study based on the quantity and location of scheduled Demand.  The ISO shall issue daily voltage schedules which are required to be maintained for ISO Control Area reliability.
All Participating Generators shall maintain the ISO specified voltage schedule at the transmission interconnection points to the extent possible while operating within the power factor range specified in their interconnection agreements or, for Regulatory Must-Take Generation, Regulatory Must-Run Generation and Reliability Must-Run Generation consistent with existing obligations.  For Generating Units,  that do not operate under one of these agreements, the minimum power factor range will be within a band of 0.90 lag (producing VARs) and 0.95 lead (absorbing VARs) power factors.  Participating Generators with Generating Units existing at the ISO Operations Date that are unable to meet this operating power factor requirement may apply to the ISO for an exemption.  Prior to granting such an exemption,  the ISO shall require the Participating TO or UDC to whose system the relevant Generating Units are interconnected to notify it of the existing contractual requirements for voltage support established prior to the ISO Operations Date for such Generating Units.  Such requirements may be contained in CPUC Electric Rule 21 or the Interconnection Agreement with the Participating TO or UDC.  The ISO shall not grant any exemption under this Section from such existing contractual requirements.  The ISO shall be entitled to instruct Participating Generators to operate their Generating Units at specified points within their power factor ranges.  Generators shall receive no compensation for operating within these specified ranges.
If the ISO requires additional Voltage Support, it shall procure this either through Reliability Must-Run Contracts or, if no other more economic source are available by instructing a Generating Unit to move its MVar output outside its mandatory range.  Only if the Generating Unit must reduce its MW output in order to comply with such an instruction will it be compensated in accordance with Section 2.5.18.
All Loads directly connected to the ISO Controlled Grid shall maintain reactive flow at grid interface points within a specified power factor band of 0.97 lag to 0.99 lead.  Loads shall not be compensated for the service of maintaining power factor at required levels within the bandwidth.  A UDC interconnecting with the ISO Controlled Grid at any point other than a Scheduling Point shall be subject to the same power factor requirement.
The power factor for both the Generating Units and Loads shall be measured at the interconnection point with the ISO Controlled Grid.  The ISO will develop and will be authorized to levy penalties against Participating Generators, UDCs or Loads whose Voltage Support does not comply with the ISO’s requirements.  The ISO will establish voltage control standards with UDCs and the operators of other Control Areas and will enter into operational agreements providing for the coordination of actions in the event of a voltage problem occurring.
Wheeling Through and Wheeling Out transactions may also be subject to a reactive charge as developed by the ISO.  If the ISO shall determine that a reactive charge should be payable at a future date, it shall, subject to FERC acceptance and approval, publish annually the Voltage Support obligations and applicable charges for Wheeling Through and Wheeling Out transactions at Scheduling Points.  The obligations shall be predetermined by the ISO based on the estimated amount of the Wheeling Through and Wheeling Out transactions each year.
2.5.3.5	Black Start Capability.  The ISO shall determine the amount and location of Black Start Generation it requires through contingency studies that are used as the basis of the ISO’s emergency plans.  The studies shall specify:
(a)	the initiating disturbance;
(b)	the magnitude of the Outage, including the extent of the Outage (local area, ISO Control Area, or WSCC), the assumed status of Generation after the initiating disturbance, the status of interconnections, the system load level at the time of the disturbance, the interconnection support, and assumptions regarding the availability of support from other utilities to help restore Generation and Demand;
(c)	the Generator performance including a percentage of Black Start units (to be determined by the ISO) which are expected to fail to start, and
(d)	expected transmission system damage.
The ISO shall also specify the following load restoration performance goals:
(i)	Black Start unit startup and connection times;
(ii)	ISO Control Area restoration times; and
(iii)	load restoration times.
Scheduling Coordinators shall provide the ISO with their load restoration time requirements for any Loads that provide emergency services.
2.5.4	Locational Quantities of Ancillary Services.
For each of the Ancillary Services, the ISO shall determine the required locational dispersion in accordance with ISO Control Area reliability requirements.  These standards shall be used as guidance only.  The actual location of Ancillary Services on a daily and hourly basis shall depend on the locational spread of Demand within the ISO Control Area, the available transmission capacity, the locational mix of Generation, and historical patterns of transmission and Generation availability.
2.5.4.1	Black Start Units.
(a)	must be located in the ISO Control Area;
(b)	may be located anywhere in the ISO Control Area provided that the Black Start resource is capable of meeting the ISO performance requirements for starting and interconnection to the ISO Controlled Grid and other portions of the ISO Control Area; but
(c)	must be dispersed throughout the ISO Control Area.
2.5.7.4	Procurement of Ancillary Services from Resources Within ISO Control Area
As of the ISO Operations Date the ISO will purchase Ancillary Services only from resources located within the ISO Control Area.  The ISO will not procure Regulation from outside of the ISO Control Area, nor will it support self provision of Regulation from resources outside the ISO Control Area except under Existing Contracts.  Scheduling Coordinators may utilize transmission service under Existing Contracts to self-provide Spinning Reserve, Non-Spinning Reserve or Replacement Reserve from resources located outside the ISO Control Area, where technically feasible, consistent with WSCC standards.  As of the ISO Operations Date the ISO will not support any other self provision of these Ancillary Services from resources located outside the ISO Control Area.
2.5.9	Provision of System Information to Market Participants.
By 6:00 p.m. two days prior to the Trading Day, the ISO shall make available to Scheduling Coordinators general system information including those items of information set forth in Section 2.2.10.  This information shall be provided at the same time as the ISO provides general system information to all Scheduling Coordinators.
2.5.12	Bid Evaluation Rules.
Bid evaluation shall be based on the following principles:
(a)	the ISO shall not differentiate between bidders other than through price and capability to provide the service, and the required locational mix of services;
(b)	to minimize the costs to users of the ISO Control Area, the ISO shall select the bidders with lowest bids for capacity which meet its technical requirements, including location and operating capability;
(c)	for the Day-Ahead Market, the Day-Ahead bids shall be evaluated independently for each of the 24 Settlement Periods of the following Trading Day;
(d)	for the Hour-Ahead Market, the ISO shall evaluate bids in the two hours preceding the hour of operation;
(e)	the ISO will procure sufficient Ancillary Services in the Day-Ahead Market to meet its technical requirements defined in the ISO Protocols.
2.5.20.3	Literal Self Provision by a Metered Subsystem.  A MSS operator must be the Scheduling Coordinator or act through a Scheduling Coordinator and must submit the Energy, Ancillary Services, and Adjustment Bids for all End Users within the MSS who are not served by other Scheduling Coordinators.
	The MSS operator may provide its Regulation Spinning Reserve, Non-Spinning Reserve, and Replacement Reserve requirements through any combination of Literal Self Provision, In-Kind Self Provision, or purchases from the ISO.  A MSS may utilize a System Unit to participate in the procurement processes of the ISO for Regulation Spinning Reserve, Non-Spinning Reserve, and Replacement Reserve.  A System Unit is defined as one or more resources within a MSS controlled by the MSS operator so as to simulate a single resource for Regulation Spinning Reserve, Non-Spinning Reserve, and Replacement Reserve with specified performance characteristics.  A System Unit must consist of resources located within the MSS or resources dynamically scheduled into the MSS.  For Regulation, Spinning Reserve, Non-Spinning Reserve, and Replacement Reserve, bid evaluation and price determination, a System Unit shall be deemed for the purposes of this Section 2.5 to be equivalent to a single Generating Unit.
A MSS may self provide all Ancillary Services eligible for self provision or may meet its requirement for such Ancillary Services by purchases from the ISO.  A MSS must schedule all its Energy and Ancillary Services for End-Users within the MSS who are not served by other Scheduling Coordinators either as a Scheduling Coordinator or through a Scheduling Coordinator.
The MSS is not a separate Control Area.  The ISO maintains the authority and control necessary to fulfill its responsibilities as the ISO Control Area operator.  The ISO shall have the authority to control Ancillary Services provided or self provided by the MSS.  The ISO maintains Operational Control of the MSS within the ISO Control Area, and performs Congestion Management within the MSS.  The ISO will develop protocols and procedures for the roles, responsibilities and requirements associated with a MSS.
2.5.24	Verification of Performance of Ancillary Services.
Availability of both contracted and self provided Ancillary Services shall be verified by the ISO by unannounced testing of Generating Units, Loads and System Resources, by auditing of response to ISO Dispatch instructions, and by analysis of the appropriate Meter Data.  Participating Generators, owners or operators of Loads and Scheduling Coordinators shall notify the ISO immediately whenever they become aware that an Ancillary Service is not available in any way.  All Participating Generators and owners or operators of Loads shall check, monitor and/or test their system and related equipment routinely to assure availability of the committed Ancillary Services.  These requirements apply whether the Ancillary Services are contracted or self provided.  For a duration specified by the ISO, the ISO may suspend the technical eligibility certificate of a Scheduling Coordinator for a Generating Unit, Load or System Resource which repeatedly fails to perform.  The ISO shall develop measures to discourage repeated non-performance on the part of both bidders and self providers.
The ISO shall monitor the performance of a MSS via a Metered Subsystem Regulation Error (MSRE).  The MSRE is obtained by comparing the sum of the metered power flows at the MSS interface points to the sum of the MSS's power scheduled or instructed at these same interface points.  The ISO may bias the MSRE for purposes of testing or control of Ancillary Services provided by the MSS.  The MSRE shall incorporate this bias.  The MSRE shall be reported to the ISO on a real time basis, and checked at five minute intervals to determine whether the MSS meets specified performance criteria.
The ISO has authority to suspend MSS control and direct, via communications with the MSS operator, the operation of units within the MSS if such control is necessary to maintain ISO Control Area reliability.
If the MSS operator does not conform with Good Utility Practice, the ISO may suspend MSS control until the MSS operator demonstrates the ability and willingness to conform with Good Utility Practice.
3.2.1.2	Reliability Driven Projects.  The ISO or the Participating TO, in coordination with the ISO and Market Participants, through the coordinated planning processes of the WSCC and the RTGs, will identify the need for any transmission additions or upgrades required to ensure system reliability consistent with all Applicable Reliability Criteria.  In making this determination, the Participating TO and the ISO, in coordination with the other Market Participants, shall consider lower cost alternatives to the construction of transmission additions or upgrades, such as acceleration or expansion of existing projects, demand-side management, remedial action schemes, constrained-on Generation, interruptible Loads or reactive support.  The Participating TO shall perform the necessary studies to determine the facilities needed to meet all Applicable Reliability Criteria.  The Participating TO shall provide the ISO and other Market Participants with all information relating to a proposed transmission addition or upgrade that they may reasonably request (other than information available to them through the WSCC or RTG) and shall, through the WSCC or RTG coordinated planning processes, develop the scope of and assumptions for such studies that are acceptable to the ISO and those other Market Participants.  The ISO shall be free to propose any transmission upgrades it deems necessary to ensure System Reliability consistent with Applicable Reliability Criteria and subject to appropriate appeals, the TO shall be obligated to construct such lines.  After the ISO Operations Date, the ISO, in consultation with  Market Participants, will work to develop a consistent set of reliability criteria for the ISO Control Area which the TOs will use in their transmission planning and expansion studies or decisions.
3.2.4	Operational Review.
The ISO will perform an operational review of all facilities that are to be connected to, or made part of, the ISO Controlled Grid or the ISO Control Area to ensure that the facilities being proposed provide for acceptable operating flexibility and meet all its requirements for proper integration with the ISO Control Area.  If the ISO finds that such facilities do not provide for acceptable operating flexibility or do not reliably integrate with the ISO Control Area, the Participating TO or Non-Participating TO (as the case may be) will reassess its determination of the facilities required to be constructed.
3.2.8.1	All transmission additions and upgrades constructed in accordance with this Section 3.2, other than additions and upgrades made to the transmission facilities of Non-Participating TOs, shall form part of the ISO Controlled Grid and shall be operated and maintained by a Participating TO in accordance with the Transmission Control Agreement.
3.3	Performance of Control Area Responsibilities
3.3.1	With effect from the ISO Operations Date, the ISO will serve as the Control Area operator of the combined Control Area operated prior to that date as separate Control Areas by the Participating TOs, in succession to those Participating TOs.  Any Participating TO which is party to an Existing Control Agreement shall ensure:
(a)	that all Energy and Ancillary Services scheduled into, out of, within or through the ISO Control Area, or across transmission facilities forming part of the ISO Controlled Grid by virtue of Entitlements but located outside the ISO Control Area under that Existing Control Agreement, are scheduled with the ISO through a Scheduling Coordinator; 
(b)	that the Non-Participating TO which is a party to the Existing Control Agreement complies with the scheduling and dispatch provisions of this Tariff including the ISO Protocols; and 
(c)	that the ISO is otherwise permitted to exercise all rights and powers under the Existing Control Agreement as required by the ISO to perform its duties and obligations under this Tariff and the ISO Protocols.
3.3.2	The ISO shall not be obliged to accept Schedules from a Scheduling Coordinator on behalf of a Participating TO which has not complied with the requirements of Section 3.3.1.
4.	Relationship Between ISO AND UDCs.
4.1	General Nature of Relationship Between ISO and UDCs.
4.1.2	The ISO shall operate all facilities under ISO jurisdiction as Control Area operator, including transmission facilities in the ISO Control Area which are the subject of Existing Control Agreements or Existing Operating Agreements and each UDC shall operate its Distribution System at all times in accordance with Good Utility Practice and in a manner which ensures safe and reliable operation.  The ISO shall, in respect of its obligations set forth in this Section 4, have the right by agreement to delegate certain operational responsibilities to the relevant Participating TO or UDC pursuant to this Section 4.  All information made available to UDC’s by the ISO shall also be made available to Scheduling Coordinators.  All information pertaining to the physical state or operation, maintenance and failure of the UDC Distribution System affecting the operation of the ISO Control Area that is made available to the ISO by the UDC shall also be made available to Scheduling Coordinators upon receipt of reasonable notice.
4.3	UDC Responsibilities.
Recognizing the ISO’s duty to ensure efficient use and reliable operation of the ISO Control Area consistent with the Applicable Reliability Criteria, each UDC shall:
4.3.1	operate and maintain its facilities, in accordance with applicable safety and reliability standards, regulatory requirements, applicable operating guidelines, applicable rates, tariffs, statutes and regulations governing their provision of service to their End-Use Customers and Good Utility Practice so as to avoid any material adverse impact on the ISO Control Area;
4.3.2	provide the ISO Outage Coordination Office each year with a schedule of upcoming maintenance that has a reasonable potential of impacting the ISO Control Area in accordance with Section 2.3.3.5 of this ISO Tariff; and
4.4.4	The ISO shall have the authority to direct a UDC to disconnect Load from the ISO Controlled Grid if necessary to avoid an anticipated System Emergency or to aid in restoring normal operation of the ISO Control Area during an actual System Emergency.  The ISO shall direct the UDCs to shed Load in accordance with the prioritization schedule developed pursuant to Section 2.3.2.6.  When ISO Control Area conditions permit restoration of Load, the ISO shall restore Load according to the prioritization schedule developed pursuant to Section 2.3.2.6 hereof.
4.7	Coordination of Expansion or Modifications to UDC Facilities.
Each UDC and the Participating TO with which it is interconnected shall coordinate in the planning and implementation of any expansion or modifications of a UDC's or Participating TO’s system that will affect their transmission interconnection, the ISO Control Area or the transmission services to be required by the UDC.  The Participating TO shall be responsible for coordinating with the ISO.
4.8.1	System Planning Studies.
The ISO, Participating TOs and UDCs shall share information such as projected Load growth and system expansions necessary to conduct necessary system planning studies to the extent that these may impact the operation of the ISO Control Area.
4.8.2	System Surveys and Inspections.
The ISO and each UDC shall cooperate with each other in performing system surveys and inspections to the extent these relate to the operation of the ISO Control Area.
5.	RELATIONSHIP BETWEEN ISO AND GENERATORS.
The ISO shall not schedule Energy or Ancillary Services generated by any Generating Unit interconnected with the ISO Control Area, or to the Distribution System of a Participating TO or of a UDC otherwise than through a Scheduling Coordinator.  The ISO shall not be obligated to accept Schedules or Adjustment Bids or bids for Ancillary Services relating to Generation from any Generating Unit interconnected with the ISO Control Area unless the relevant Generator undertakes in writing to the ISO to comply with all applicable provisions of this ISO Tariff as they may be amended from time to time, including, without limitation, the applicable provisions of this Section 5 and Section 2.3.2.
5.1.3	Actions for Maintaining Reliability of ISO Control Area.
The ISO plans to obtain the control over Generating Units that it needs to control the ISO Control Area and maintain reliability by purchasing Ancillary Services from the market auction for these services.  When the ISO responds to events or circumstances, it shall first use the generation control it is able to obtain from the Ancillary Services bids it has received to respond to the operating event and maintain reliability.  Only when the ISO has used the Ancillary Services that are available to it under such Ancillary Services bids which prove to be effective in responding to the problem and the ISO is still in need of additional control over Generating Units, shall the ISO assume supervisory control over other Generating Units.  It is expected that at this point, the operational circumstances will be so severe that a real-time system problem or emergency condition could be in existence or imminent.
Each Participating Generator shall take, at the direction of the ISO, such actions affecting such Generator as the ISO determines to be necessary to maintain the reliability of the ISO Control Area.  Such actions shall include (but are not limited to):
(a)	compliance with the ISO’s Dispatch instructions including instructions to deliver Ancillary Services in real time pursuant to the Final Day-Ahead Schedules and Final Hour-Ahead Schedules;
(b)	compliance with the system operation requirements set out in Section 2.3 of this ISO Tariff;
(c)	notification to the ISO of the persons to whom an instruction of the ISO should be directed on a 24-hour basis, including their telephone and facsimile numbers; and
(d)	the provision of communications, telemetry and direct control requirements, including the establishment of a direct communication link from the control room of the Generator to the ISO in a manner that ensures that the ISO will have the ability, consistent with this ISO Tariff and the ISO Protocols, to direct the operations of the Generator as necessary to maintain the reliability of the ISO Control Area.
5.2	Procurement of Reliability Must-Run Generation by the ISO.
5.2.1	A Reliability Must-Run Contract is a contract entered into by the ISO with a Generator which operates a Generating Unit giving the ISO the right to call on the Generator to generate Energy and provide Ancillary Services from the Generating Units as and when this is required to ensure that the reliability of the ISO Control Area is maintained.
5.2.3	The ISO will, subject to any existing power purchase contracts of a Generating Unit, have the right at any time based upon ISO Control Area technical analyses and studies to designate a Generating Unit as a Reliability Must-Run Unit.  A Generating Unit so designated shall then be obligated to provide the ISO with its proposed rates for Reliability Must-Run Generation for negotiation with the ISO and authorization by FERC.
5.2.4	Prior to the ISO Operations Date, the ISO will carry out a technical study to identify which Generating Units it will require to be the subject of a Reliability Must-Run contract.  This study will be based upon a technical evaluation of the anticipated ISO Control Area operation as from the ISO Operations Date.
5.2.5	On a yearly basis, the ISO will carry out further technical evaluations based upon historic patterns of the operation of the ISO Control Area and the ISO's forecast requirements for maintaining the reliability of the ISO Control Area in the next year.  The ISO will then determine which Generating Units it requires to continue to be Reliability Must-Run Units, which Generating Units it no longer requires to be Reliability Must-Run Units and which Generating Units it requires to become the subject of a Reliability Must-Run contract which had not previously been so contracted to the ISO.
5.2.6	A pro forma of the Reliability Must-Run Contract is attached as Appendix G.  From the ISO Operations Date all Reliability Must-Run Units will be placed under the “As Called” conditions, but the parties may, pursuant only to the terms of the Reliability Must-Run Contract, transfer any such unit to one of the alternative forms of conditions under specific circumstances.  The ISO will review the terms of the applicable forms of agreement applying to each Reliability Must-Run Unit to ensure that the ISO will procure Reliability Must-Run Generation from the cheapest available sources and to maintain System Reliability.  The ISO shall give notice to terminate Reliability Must-Run contracts that are no longer necessary or can be replaced by less expensive and/or more competitive sources for maintaining the reliability of the ISO Control Area.

5.6	System Emergencies.
5.6.1	All Generating Units and System Resources that are owned or controlled by a Participating Generator are (without limitation to the ISO’s other rights under this ISO Tariff) subject to control by the ISO during a System Emergency and in circumstances in which the ISO considers that a System Emergency is imminent or threatened.  The ISO shall, subject to Section 5.6.2, have the authority to instruct a Participating Generator to bring its Generating Unit on-line, off-line, or increase or curtail the output of the Generating Unit and to alter scheduled deliveries of Energy and Ancillary Services into or out of the ISO Control Area, if such an instruction is reasonably necessary to prevent an imminent or threatened System Emergency or to retain Operational Control over the ISO Controlled Grid or to preserve the reliability of the ISO Control Area during an actual System Emergency.
5.8	Recordkeeping; Information Sharing.
5.8.1	Requirements for Maintaining Records.
Participating Generators shall provide to the ISO such information and maintain such records as are reasonably required by the ISO to plan the efficient use and maintain the reliability of the ISO Control Area.
5.8.4	Sharing Information on Reliability of ISO Control Area.
The ISO and each Participating Generator shall have the obligation to inform each other, as promptly as possible, of any circumstance of which it becomes aware (including, but not limited to, abnormal temperatures, storms, floods, earthquakes, and equipment depletions and malfunctions and deviations from the Registered Data and operating characteristics) that is reasonably likely to threaten the reliability of the ISO Control Area or the integrity of the Participating Generator’s facilities.  The ISO and each Participating Generator shall also inform the other as promptly as possible of any incident of which it becomes aware (including, but not limited to, equipment outages, over-loads or alarms) which, in the case of a Participating Generator, is reasonably likely to threaten the reliability of the ISO Control Area or, in the case of the ISO, is reasonably likely to adversely affect the Participating Generator's facilities.  Such information shall be provided in a form and content which is reasonable in all the circumstances and sufficient to provide timely warning to the other party of the threat.
5.10.3	The ISO shall have the sole right to determine when the operation of Black Start Generating Units is required to respond to conditions within the ISO Control Area.
6.1.2.3	WEnet shall be used by the ISO to post Usage Charges for Inter-Zonal Interfaces for Congestion Management purposes.
6.1.2.6	WEnet shall be used by the ISO to provide information to Market Participants regarding the ISO Control Area.  Such information may include but is not limited to:
6.2.2	The ISO shall arrange for the Internet Service Provider to provide a pathway for public Internet connectivity through the WEnet backbone to accommodate users other than Market Participants without the need for a separate, dedicated user data link.  This public Internet connection may provide a reduced level of data exchange and reduced information concerning the reliability and performance of the ISO Control Area when compared to that provided to Market Participants through dedicated user data links.
7.2.1.2	Zone-Based Approach.  The ISO will use a Zone-based approach to manage Congestion.  A Zone is a portion of the ISO Control Area within which Congestion is expected to occur infrequently or have relatively low Congestion Management costs.  Inter-Zonal Interfaces consist of transmission facilities that are expected to have relatively high Congestion Management costs, as described in Section 7.2.7.1.  For these interfaces, allocation of usage based on the value placed on these interfaces by the Scheduling Coordinators will increase efficient use of the ISO Control Area.
7.2.7.3.4	The initial inactive Inter-Zonal Interfaces are the interface between the San Francisco Zone and the remainder of the ISO Control Area, and the interface between the Humboldt Zone and the remainder of the ISO Control Area.  The initial Inactive Zones are the San Francisco Zone and the Humboldt Zone.
7.3.2	Grid Operations Charge for Intra-Zonal Congestion.
Scheduling Coordinators whose resources are redispatched by the ISO, in accordance with Intra-Zonal Congestion Management, and in order to accommodate Reliability Must-Run Generation which the ISO requests under Reliability Must-Run Contracts will be paid or charged based on the Adjustment Bids that they have provided to the ISO.  After deduction of the amounts paid for Reliability Must-Run Generation under Section 7.2.6.2, the net redispatch cost in each Zone will be recovered through the Grid Operations Charge, which shall be calculated by the ISO for each Settlement Period and shall be paid to the ISO by all Scheduling Coordinators in proportion to their metered Demand within, and metered exports from, the Zone plus exports from the Zone to adjacent Control Areas.
7.4.2	Determination of Transmission Losses.
The total Demand that may be served by a Generating Unit, in a given hour, taking account of Transmission Losses, is equal to the product of the total Metered Quantity of that Generating Unit in that hour and the Generation Meter Multiplier calculated by the ISO in the hour for that Generator location.  The Generation Meter Multiplier shall be greater than one (1) where the Generating Unit’s contribution to the ISO Control Area reduces Transmission Losses and shall be less than one (1) where the Generating Unit’s contribution to the system increases Transmission Losses.  All Generating Units supplying Energy to the ISO Control Area at the same electrical bus shall be assigned the same Generation Meter Multiplier.
7.4.2.1	Procedures for Calculating Generation Meter Multiplier.  By 6:00 p.m. two days preceding a Trading Day, the ISO will calculate, and post on WEnet, an estimated Generation Meter Multiplier for each electrical bus at which one or more Generating Units may supply Energy to the ISO Control Area.  The Generation Meter Multipliers shall be determined utilizing the Power Flow Model based upon the ISO’s forecasts of total Demand for the ISO Control Area and Demand and Generation patterns throughout the ISO Control Area.  The ISO shall continuously update the data to be used in calculating the Generation Meter Multipliers to reflect changes in system conditions in the ISO Control Area, and the ISO shall provide all Scheduling Coordinators with access to such data.  The ISO shall not be required to determine new Generation Meter Multipliers for each hour; the ISO will determine the appropriate period for which each set of Generation Meter Multipliers will apply, which period may vary based upon the expected frequency and magnitude of changes in system conditions in the ISO Control Area.
7.4.2.2.2	The ISO shall calculate the Full Marginal Loss Rate for each Generating Unit location for an hour by utilizing the Power Flow Model to calculate the effect on total Transmission Losses for the ISO Control Area of injecting an increment of Generation at each such Generating Unit location to serve an equivalent incremental MW of Demand distributed on a pro-rata basis throughout the ISO Control Area.
8.3	Allocation of the Grid Management Charge Among Scheduling Coordinators.
The Grid Management Charge shall be levied monthly in arrears on all Scheduling Coordinators by charging each Scheduling Coordinator the product of the Grid Management Charge rate as calculated under Section 8.4, and the monthly metered consumption in MWh of Energy (including Wheeling Out and Wheeling Through the ISO Controlled Grid or the ISO Control Area) for that Scheduling Coordinator or by such other method as shall be approved by the ISO Governing Board and filed with FERC.
11.	ISO SETTLEMENTS AND BILLING.
11.1	Settlement Principles.
11.1.1	The ISO shall calculate, account for and settle transactions in accordance with the following principles:
11.1.2	The ISO shall be responsible for calculating Settlement balances for all transactions carried out by Scheduling Coordinators in the ISO Control Area in each Settlement Period;
11.2.4	Imbalance Energy.
The ISO shall calculate, account for and settle Imbalance Energy in the Real Time Market for each Settlement Period for the relevant Zone within the ISO Control Area or Scheduling Point.
11.2.4.3	Unaccounted For Energy (UFE)
UFE is treated as Imbalance Energy.  For each Settlement Period, the ISO will calculate UFE in the ISO Control Area, for each UDC Service Area.  The UFE will be included in the net settlements for Imbalance Energy in Section 11.2.4.1.  UFE attributable to meter measurement errors, load profile errors, Energy theft, and distribution loss deviations will be allocated to each Scheduling Coordinator based on the ratio of their metered Demand (including exports to neighboring Control Areas) within the relevant UDC Service Area to total metered Demand within the UDC Service Area.
12.	AUDITS.
12.1	Materials Subject to Audit.
The ISO’s financial books, cost statements, accounting records and all documentation pertaining to its operation as a state chartered independent institution which controls the operation of the ISO Control Area to ensure open, non-discriminatory transmission access for all Market Participants and promotes the efficient use and reliable operation of the ISO Controlled Grid in accordance with this ISO Tariff, are subject to audit in the manner prescribed below:
16.	ISO TECHNICAL ADVISORY COMMITTEE; CHANGES TO ISO protocols.
16.1	ISO Technical Advisory Committee.
The ISO Technical Advisory Committee shall coordinate activities relating to the ISO Control Area and shall consider suggestions for changes to the ISO Protocols in accordance with the procedures set out in Article IV, Section 4 of the ISO’s bylaws.
20.1.3	Notice of Changes in Operating Rules and Protocols.
The ISO shall give all Market Participants notice of at least thirty (30) days of any changes or proposed changes in its operating rules, procedures and protocols, unless:  (1) a different notice period is specified by state or Federal law or (2) the change is reasonably required to address an emergency affecting the ISO Control Area or its operations, in which case the ISO shall give Market Participants as much notice as is reasonably practicable.  Any notices issued under this provision shall be delivered in accordance with the procedures set out in Section 20.1 of this ISO Tariff.
Master Definitions Supplement
Administrative Price	The price set by the ISO in place of a Market Clearing Price when, by reason of a System Emergency, the ISO determines that it no longer has the ability to maintain reliable operation of the ISO Control Area relying solely on the economic Dispatch of Generation.  This price will remain in effect until the ISO considers that the System Emergency has been contained and corrected.
	
Ancillary Services	Regulation, Spinning Reserve, Non-Spinning Reserve, Replacement Reserve, Voltage Support and Black Start together with such other interconnected operation services as the ISO may develop in cooperation with Market Participants to support the transmission of Energy from Generation resources to Loads while maintaining reliable operation of the ISO Control Area in accordance with Good Utility Practice.
	
Black Start	The procedure by which a Generating Unit self-starts without an external source of electricity thereby restoring power to the ISO Control Area following system or local area blackouts.
	
Curtailable Demand	Demand that can be curtailed at the direction of the ISO in the real time dispatch of the ISO Control Area.  Scheduling Coordinators with Curtailable Demand may offer it to the ISO to meet Non-spinning or Replacement Reserve requirements.
	
Existing Control Agreement	An agreement entered into prior to the ISO Operations Date, the parties to which include a Participating TO and a Non-Participating TO, relating to transmission rights, transmission facilities, or scheduling rights (including those relating to Scheduling Points) which do not form part of the ISO Controlled Grid but for which the ISO has responsibility as Control Area operator and in relation to which the Participating TO has acted as Control Area operator and has scheduled the use of such transmission facilities or rights.
	
Existing Operating Agreement	The agreement between the ISO and an Existing Operating Entity relating to the operation of the subsystem of that Existing Operating Entity.
	
Grid Management Charge	The ISO monthly charge on all Scheduling Coordinators that is intended to recover all of the ISO’s costs (including, but not limited to, startup, development and financing costs and the costs of ongoing operation and maintenance) associated with its Control Area operator responsibilities and obligations and its costs in administering the scheduling, bidding, dispatch, and settlement of all Energy and Ancillary Services, which shall be calculated as set out in Section 8 of the ISO Tariff.
	
Imbalance Energy	The real time change in Generation output or Demand (from dispatchable Generating Units or Loads) which is instructed by the ISO to ensure that reliability of the ISO Control Area is maintained in accordance with Applicable Reliability Criteria.  Sources of Imbalance Energy include Regulation, Spinning and Non-spinning Reserves, Replacement Reserve, and Energy from other Generating Units that are able to respond to the ISO's request for more or less Energy.
	
Inter-Zonal Interface	The (i) group of transmission paths between two adjacent Zones of the ISO Control Area, for which a physical, non-simultaneous transmission capacity rating (the rating of the interface) has been established or will be established prior to the use of the interface for Congestion Management; (ii) the group of transmission paths between an ISO Zone and an adjacent Scheduling Point, for which a physical, non-simultaneous transmission capacity rating (the rating of the interface) has been established or will be established prior to the use of the interface for Congestion Management; or (iii) the group of transmission paths between two adjacent Scheduling Points, where the group of paths has an established transfer capability and established transmission rights.
	
Interruptible Imports	Energy sold by a Generator or resource located outside the ISO Control Area which by contract can be interrupted or reduced at the discretion of the seller.
	
ISO Control Area	The ISO electric power system (initially comprising the electric power systems previously operated as Control Areas by PG&E, SCE, and SDG&E, including but not limited to, the facilities and Entitlements which represent the ISO Controlled Grid), for which the ISO has reliability responsibilities pursuant to NERC and WSCC requirements.  The ISO’s AGC scheme applies to this system, in order to:
i)	match, at all times, the power output of Scheduling Coordinators’ Generating Units within the ISO electric power system, plus the Energy imported by Scheduling Coordinators from entities located beyond the ISO’s points of interchange with adjoining Control Areas, minus Energy exported by Scheduling Coordinators to entities located beyond the ISO’s points of interchange with adjoining Control Areas, with Scheduling Coordinators’ Demand within the ISO electric power system;
ii)	maintain scheduled interchange with other Control Areas, within the limits of Good Utility Practice;
iii)	maintain the frequency of the ISO electric power system within reasonable limits in accordance with Good Utility Practice; and 
iv)	provide sufficient generating capacity to maintain Operating Reserves in accordance with Good Utility Practice.
	
ISO Controlled Grid	The system of transmission lines and associated facilities and Entitlements of the Participating TOs that have been placed under the ISO’s Operational Control.
	
ISO Operations Date	The date on which the ISO first assumes responsibility for the ISO Control Area and Operational Control of the ISO Controlled Grid.
	
ISO Protocols	The rules, protocols, procedures and standards attached to the ISO Tariff as Appendix L, promulgated by the ISO (as amended from time to time) to be complied with by the ISO Scheduling Coordinators, Participating TOs and all other Market Participants in relation to the operation of the ISO Control Area and the participation in the markets for Energy and Ancillary Services in accordance with the ISO Tariff.
	
Market Participant	An entity, including a Scheduling Coordinator, who participates in the Energy marketplace through the buying, selling, transmission, or distribution of Energy or Ancillary Services into, out of, or through the ISO Control Area.
	
MSS (Metered Subsystem)	A system of an Existing Operating Entity as at the ISO Operations Date which has been operating for a number of years, is subsumed within the ISO Control Area, and encompassed by revenue quality meters at each interface point with the ISO Controlled Grid or the rest of the ISO Control Area which is operated in accordance with Existing Contracts, Existing Control Agreements or Existing Operating Agreements.
	
Non-Participating TO	A TO or an Existing Operating Entity that is not a party to the TCA or for the purposes of Sections 2.4.3 and 2.4.4 of the ISO Tariff the holder of transmission service rights under an Existing Contract that is not a Participating TO.
	
Operating Procedures	Procedures governing the operation of the ISO Control Area as the ISO may from time to time develop, and/or procedures that Participating TOs currently employ which the ISO adopts for use.
	
Operator	The operator of facilities under ISO jurisdiction as Control Area operator including transmission facilities on the ISO Control Area which are the subject of Existing Control Agreements or Existing Operating Agreements, and Reliability Must-Run Units.
	
Participating Seller or Participating Generator	A Generator or other seller of Energy or Ancillary Services through a Scheduling Coordinator over the ISO Controlled Grid or a portion of the ISO Control Area, or at a Scheduling Point, and which has undertaken to be bound by the terms of the ISO Tariff.
	
PMS (Power Management System)	The ISO computer control system used to monitor the real time performance of the various elements of the ISO Control Area, control Generation, and perform operational power flow studies.
	
Power Flow Model	The computer software used by the ISO to model the voltages, power injections and power flows on the ISO Control Area and determine the expected Transmission Losses and Generation Meter Multipliers.
	
Reactive Power Control	Generation or other equipment needed to maintain acceptable voltage levels in the ISO Control Area and to meet reactive capacity requirements at points of interconnection in the ISO Control Area.
	
Registered Data	Those items of technical data and operating characteristics relating to Generation, transmission or distribution facilities which are identified to the owners of such facilities as being information, supplied in accordance with ISO Protocols, to assist the ISO to maintain reliability of the ISO Control Area and to carry out its functions.
	
Reliability Criteria	Pre-established criteria that are to be followed in order to maintain desired performance of the ISO Control Area under contingency or steady state conditions.
	
Reliability Must-Run Contract	A contract entered into by the ISO with a Generator which operates a Generating Unit giving the ISO the right to call on the Generator to generate Energy and/or provide Ancillary Services from the Generating Unit as and when this is required to ensure the reliability of the ISO Control Area.

Reliability Must-Run Unit	
A Generating Unit which is the subject of the contract between the Generator and the ISO under which, in return for certain payments, the ISO is entitled to call upon the owner to run the unit when required by the ISO for the purposes of the reliable operation of the ISO Control Area.
	
Replacement Reserve	Generating capacity that is dedicated to the ISO, capable of starting up if not already operating, being synchronized  and ramping to a specified load point within a sixty (60) minute period, the output of which can be continuously maintained for a two hour period.  Also, Curtailable Demand that is capable of being curtailed within sixty minutes and that can remain curtailed for two hours.
	
Scheduling Point	A location at which the ISO Control Area, or a portion of the ISO Controlled Grid located outside the ISO Control Area, is connected, by a group of transmission paths for which a physical, non-simultaneous transmission capacity rating has been established for Congestion Management, to transmission facilities that are located within another Control Area. “”  For most practical purposes, a Scheduling Point can be considered to be a Zone that is outside the ISO Control Area.
	
Security Monitoring	The real time assessment of the ISO Control Area that is conducted to ensure that the system is operating in a secure state, and in compliance with all Applicable Reliability Criteria.
	
Suggested Adjusted Schedule	The output of the ISO's initial Congestion Management for each Scheduling Coordinator for the Day-Ahead Market (“Suggested Adjusted Day-Ahead Schedule”) or for the Hour-Ahead Market (“Suggested Adjusted Hour-Ahead Schedule”).  These Schedules will reflect ISO suggested adjustments to each Scheduling Coordinator's Preferred Schedule to resolve Inter-Zonal Congestion based on the Adjustment Bids submitted.  These schedules will be balanced with respect to Generation, Transmission Losses, Load, and trades between Scheduling Coordinators to resolve Inter-Zonal Congestion.
	
Supply	The rate at which Energy is delivered to the ISO Control Area measured in units of watts or standard multiples thereof, e.g., 1,000W=1 KW; 1,000 KW = 1MW, etc.
	
System Planning Studies	Reports summarizing studies performed to assess the adequacy of the ISO Control Area as regards conformance to Reliability Criteria.
	
System Resource	A group of resources located outside of the ISO Control Area capable of providing Energy and/or Ancillary Services to the ISO Control Area.
	
WEnet (Western Energy Network)	An electronic network that facilitates communications and data exchange among the ISO, Market Participants and the public in relation to the status and operation of the ISO Control Area.
	
Zone	A portion of the ISO Control Area within which Congestion is expected to be small in magnitude or to occur infrequently.  “Zonal” shall be construed accordingly.	

Scheduling Coordinator Agreement
THIS AGREEMENT is made this ___ day of ________________, _____ and is entered into, by and between:

(1)	[Full legal name] having a registered or principal executive office at [address] (the “Scheduling Coordinator”)
and

(2)	CALIFORNIA INDEPENDENT SYSTEM OPERATOR CORPORATION, a California nonprofit public benefit Corporation having a principal executive office located at such place in the State of California as the ISO Governing Board may from time to time designate (the “ISO”).
Whereas:
A.	The Scheduling Coordinator has applied for certification by the ISO under the certification procedure referred to in Section 2.2.3 of the ISO Tariff.
B.	The Scheduling Coordinator wishes to schedule Energy and Ancillary Services into, out of, within or through the ISO Control Area or across transmission facilities forming part of the ISO Controlled Grid by virtue of Entitlements but located inside the ISO Control Area, under the terms and conditions set forth in the ISO Tariff and the ISO Protocols.
NOW IT IS HEREBY AGREED as follows:
1.	Definitions
A.	Terms and expressions used in this Agreement shall have the same meanings as those contained in the Master Definitions Supplement to the ISO Tariff.

B.	The “ISO Tariff” shall mean the ISO Operating Agreement and Tariff as amended from time to time, together with any Appendices or attachments thereto.

2.	Covenant of the Scheduling Coordinator
The Scheduling Coordinator agrees that:
A.	the ISO Tariff and the ISO Protocols govern all aspects of scheduling of Energy and Ancillary Services into, out of, within or through the ISO Control Area or across transmission facilities forming part of the ISO Controlled Grid by virtue of Entitlements but located inside the ISO Control Area, including (without limitation), the financial and technical criteria for Scheduling Coordinators, bidding, settlement, information reporting requirements and confidentiality restrictions;

B.	it will abide by, and will perform all of the obligations under the ISO Tariff and the ISO Protocols placed on Scheduling Coordinators in respect of all matters set forth therein including, without limitation, all matters relating to the scheduling of Energy and Ancillary Services into, out of, within or through the ISO Control Area or across transmission facilities forming part of the ISO Controlled Grid by virtue of Entitlements but located inside the ISO Control Area, ongoing obligations in respect of scheduling, Settlement, system security policy and procedures to be developed by the ISO from time to time, billing and payments, confidentiality and dispute resolution;

C.	it shall ensure that each UDC, over whose Distribution System Energy or Ancillary Services are to be transmitted in accordance with Schedules, Adjustment Bids or bids for Ancillary Services submitted to the ISO by the Scheduling Coordinator, enters into a UDC operating agreement in accordance with Section 4 of the ISO Tariff;

D.	it shall ensure that each Generator for which it schedules Energy or on whose behalf it submits to the ISO Adjustment Bids or bids for Ancillary Services enters in to a Generator agreement in accordance with Section 5 of the ISO Tariff;

E.	it shall have the primary responsibility to the ISO, as principal, for all Scheduling Coordinator payment obligations under the ISO Tariff and the ISO Protocols

F.	its status as a Scheduling Coordinator is at all times subject to the ISO Tariff and the ISO Protocols.

3.	Term and Termination
3.1	This Agreement shall commence on the later of (a) __________ or (b) the date the Scheduling Coordinator is certified by the ISO as a Scheduling Coordinator.
3.2	This Agreement may terminate in accordance with the provisions set forth in the ISO Tariff and the Scheduling Coordinator Application Protocol.
4.	Assignment
Either party may assign its obligations under this Agreement with the other party’s consent, such consent shall not to be unreasonably withheld.

Black Start Units
The following requirements must be met by Generating Units providing Black Start (“Black Start Units”):

(a)	Black Start Units must be capable of starting and paralleling with the ISO Control Area without aid from the ISO Control Area;
(b)	Black Start Units must be capable of making a minimum number of starts per event (to be without aid from the ISO Control Area as determined by the ISO);
(c)	Black Start Units must be equipped with governors capable of operating in the stand alone (asynchronous) and parallel (synchronous) modes.
(d)	Black Start Units must have startup load pickup capabilities at a level to be determined by the ISO, including total startup load (MW) and largest startup load (MW) for such power output levels as the ISO may specify.
(e)	All Black Start Units must be capable of producing Reactive Power (boost) and absorbing Reactive Power (buck) as required by the ISO to control system voltages.  This requirement may be met by the operation of more than one Black Start unit in parallel providing that:
	(i)	the Black Start generation supplier demonstrates that the proposed Generation resource shares reactive burden equitably;
	(ii)	all Participating Generators associated with the proposed Black Start source are located in the same general area.
Buck/boost capability requirement shall be dependent on the location of the proposed resource in relation to Black Start load.
(f)	All Black Start Units must have the following communication/control requirements:
	(i)	dial-up telephone;
	(ii)	backup radio;
	(iii)	manning levels which accord with Good Utility Practice.

Verification of Submitted Data for Ancillary Services
The ISO shall use the following procedures for verifying the scheduling and bid information submitted by Scheduling Coordinators for Ancillary Services.  In this Appendix, a “bid” is a bid submitted by a Scheduling Coordinator in the ISO's competitive Ancillary Services market.  A “schedule” is a Schedule including Ancillary Services which the Scheduling Coordinator wishes to self-provide.

1.	Bid File and Schedule Format.  The ISO shall verify that the bid files and schedules conform to the format specified for the type of Ancillary Service bid or schedule submitted.  If the bid file or schedule does not conform to specifications, it shall be annotated by the ISO to indicate the location of the errors, and returned to the Scheduling Coordinator for corrections.  Any changes made by a Scheduling Coordinator shall require a new submittal of bid or schedule information, and all validity checks shall be performed on the re-submitted bid or schedule.
2.	Generation Schedules and Bids.
2.1.	Quantity Data.  The ISO shall verify that no Scheduling Coordinator is submitting a scheduled or bid quantity for Regulation, Spinning Reserve, Non-Spinning or Replacement Reserve which exceeds available capacity for Regulation and Reserves on the Generating Units, Loads and resources scheduled for that Settlement Period.
2.2	Location Data.  The ISO shall verify that the location data corresponds to the ISO Control Area interconnection data.
2.3.	Operating Capability.  The ISO shall verify that the operating capability data corresponds to the ISO Control Area interconnection data for each Generating Unit, Load or other resource for which a Scheduling Coordinator is submitting an Ancillary Service bid or schedule.
3.	Load Schedules and Bids.
3.1.	Quantity data.  The ISO shall verify that the quantity of Non-Spinning and Replacement Reserve scheduled or bid from Dispatchable Load does not exceed scheduled consumption quantities for that Settlement Period.
3.2.	Location data.  The ISO shall verify that the location of the Dispatchable Load corresponds to the ISO Control Area interconnection data for each supplier of Dispatchable Load.