ࡱ>  2bjbjupup e,H,HUUUUUtVVVVXDV1KZZ[[[ ]| JJJJJJJ$NQ*JU ] ]JUU[[4J$U[U[JJV.[sq&JJ<1Kt(QwQ."2.QUF.<d.t2idddJJddd1KQddddddddd,H LT:  app Manual for Market Operations Manual M-11 Revision: 49 Effective Date: May 27, 2015 Prepared by app. app Manual for Market Operations Table of Contents Introduction About This Manual INT-1 Section 1: Overview of Energy Market Operations 1.1 Scope & Purpose of Scheduling and Dispatching 1-1 1.2 app Responsibilities 1-2 1.2.1 Day-Ahead Energy Market 1-2 1.2.2 Real-Time Energy Market 1-2 1.3 Market Participant Responsibilities 1-4 1.3.1 Market Participants Buying from Energy Market 1-4 1.3.2 Market Participants Selling into Energy Market 1-4 1.3.3 Market Participants wheeling Energy through the New England Control Area 1-5 1.3.4 Market Participants Participating with Real-Time Demand Response and Real-Time Emergency Generation Resources 1-6 1.3.4.1 Data Requirements for Real-Time Demand Response and Real-Time Emergency Generation Resources 1-6 1.4 Non-Market Participant Transmission Customer Responsibilities 1-7 Section 2: Energy Market 2.1 Pricing Locations 2-1 2.2 Energy Market Business Rules 2-3 2.2.1 Bidding & Operations Time Line 2-3 2.2.2 Market Participants Buying from Energy Market 2-4 2.2.2.1 Demand Bids 2-4 2.2.2.2 Decrement Bids 2-5 2.2.2.3 External Transactions (Exports) 2-5 2.2.3 Market Participants Selling into Energy Market 2-6 2.2.3.1 Generating Resources 2-6 2.2.3.2 Increment Offers 2-9 2.2.3.3 External Transactions (Imports) 2-9 2.2.3.4 Demand Response Resources 2-10 2.2.4 Non-Market Participant Transmission Customers 2-10 2.2.5 Designation as Real-Time Reserve and Declaration of Limited Energy Resource Status 2-10 2.2.6 Technical Rules 2-11 2.2.7 Major Modeling Assumptions 2-12 2.2.8 Reserved 2-13 2.2.9 Reserved 2-13 2.2.10 Emergency Conditions in the Real-Time Energy Market 2-13 2.2.10.1 Capacity Deficient Conditions 2-13 2.2.10.2 Minimum Generation Conditions 2-14 Section 3: Scheduling 3.1 Treatment of Certain Resources 3-1 3.1.1 Local Second Contingency Protection Resources 3-1 3.1.2 Special Constraint Resources 3-1 3.1.3 Self-Scheduled Dispatchable Asset Related Demand Resources 3-1 3.2 External Transactions 3-2 3.2.1 External Transaction Submission Deadlines 3-2 3.2.2 General Information 3-2 3.2.3 Ramps 3-3 3.2.4 EES Data Requirements 3-3 3.2.4.1 Day-Ahead Energy Market 3-3 3.2.4.2 Real-Time Energy Market 3-3 3.2.5 External Transaction Requests 3-6 3.2.6. app Emergency Energy Purchases during Emergency Conditon 3-7 3.2.7 app Purchases of New Brunswick Security Energy 3-7 Revision History Approval REV-1 Revision History REV-1 app Manual for Market Operations List of Figures and Tables Exhibit 2.1: Single P-Node Mapped to Multiple Close E-Nodes 2-2 Table 3.1: Available Exceptions Associated with External Transactions 3-5 Introduction About This Manual This is the app Manual for Market Operations. The reader is referred first to Market Rule 1 for an explanation and information regarding the operation of the markets. Terms that are capitalized in this manual generally are defined in Section I of the app Tariff. This manual provides additional implementation or other detail for those provisions of Market Rule 1 that require the Market Participant to take an action. Section 1: Overview of Energy Market Operations 1.1 Scope & Purpose of Scheduling and Dispatching Operation of the New England Control Area involves many activities that are performed by different operating and technical personnel. These activities occur in parallel on a continuous basis, 24 hours a day and can be grouped into three overlapping time frames: Pre-scheduling operations Scheduling operations and the Day-Ahead Energy Market Scheduling and dispatching operations and the Real-Time Energy Market In this manual we focus on the scheduling activities associated with the Day-Ahead Energy Market, scheduling activities that take place in the Real-Time Energy Market throughout the Operating Day and Real-Time Energy Market dispatching activities that take place within the operating hour. Resources fall into one of two categories, Resources with a Capacity Supply Obligation or Resources without a Capacity Supply Obligation. For the remainder of this document Resources with a Capacity Supply Obligation shall be referred to as CSO Resources, and Resources without any Capacity Supply Obligation shall be referred to as Non-CSO Resources. 1.2 app Responsibilities 1.2.1 Day-Ahead Energy Market In the Day-Ahead Energy Market, the app determines the least-cost means of satisfying the cleared Demand Bids, cleared Decrement Bids, Operating Reserve, Replacement Reserve, Local Second Contingency Protection Resource requirements and other applicable Ancillary Services requirements of Market Participants, including the reliability requirements of the New England Control Area. Real-Time Energy Market Following the Day-Ahead Energy Market scheduling process, after the Real-Time Re-Offer Period and, as needed, throughout the Operating Day, the app will commit and de-commit Resources through the Reserve Adequacy Analysis, based upon the apps forecast of actual loads (including some External Transactions), resource availability and Self-Scheduled Resources for the next Operating Day, to: (1) Satisfy Operating Reserve and Replacement Reserve requirements of the New England Control Area by minimizing the cost to provide additional Operating Reserve, Replacement Reserve and additional Local Second Contingency Protection Resources above what was scheduled in the Day-Ahead Energy Market, if required; (2) Provide other Ancillary Services requirements, as required; and (3) Satisfy all other reliability requirements of the New England Control Area. When additional capacity must be committed through the Resource Adequacy Analyses to meet New England Control Area requirements, the commitment objective is to minimize the total cost to commit the Resource and operate it at its Economic Minimum Limit or Minimum Consumption Limit for the greater of the Resources Minimum Run Time or for the duration of the capacity requirement. (1) In making this determination, the app identifies available generating Resources that can be released for dispatch during or before the hours of need based on their state (Hot Intermediate, or Cold), Notification Times and Start-Up Times; (2) The identified Resources are ranked in ascending order based on the sum of the applicable Start-Up Fee, No-Load Fee and the cost to operate at their Economic Minimum Limits or Minimum Consumption Limits for the longer of their Minimum Run Times or the duration of the capacity requirement; (3) The set of Resources that meets the capacity requirement at the least cost are committed. If a Market Participant has procured gas for a gas-fired generating Resource that is ordered to come on-line after the close of the Day-Ahead Energy Market, the start-up will not be cancelled unless there is a reliability concern that needs to be addressed. When a gas-fired generating Resource is given an hourly commitment schedule in the Reserve Adequacy Analysis, the app will honor the hourly commitment schedule at the Resources Economic Minimum Limit for the Commitment Period, unless there is a reliability concern that needs to be addressed. In Real-Time, the app monitors and controls the New England Control Area such that the least-cost means of satisfying the projected Energy, Regulation, Operating Reserve, Replacement Reserve and other Ancillary Services requirements, including the reliability requirements of the New England Control Area, are met. Hourly scheduling of External Transactions during Real-Time occurs prior to the hour being scheduled during the Operating Day unless operating protocols exist between the app and the applicable neighboring Control Area to permit scheduling on shorter intervals and use of such shorter intervals is noted in the associated app System Operating Procedures. 1.3 Market Participant Responsibilities Only Market Participants with settlement accounts for the Energy Market are eligible to submit Supply Offers, Increment Offers, Demand Reduction Offers, Demand Bids, External Transactions (other than Through Service External Transactions) and Decrement Bids and purchase Energy or related services in the Day-Ahead Energy Market and in the Real-Time Energy Market. All Market Participants and Non-Market Participant Transmission Customers may submit Through Service External Transactions in the Real-Time Energy Market. The major responsibilities of Market Participants are as follows: 1.3.1 Market Participants Buying from Energy Market Market Participants may submit hourly Demand Bids for the amount of demand that they want to participate in the Day-Ahead Energy Market. Any Market Participant that owns a Dispatchable Asset Related Demand, except for pumping demand of a pumped storage generator without a Capacity Supply Obligation, must submit a Demand Bid for the Resource as described in Market Rule 1 Section III.1.10.6. The key scheduling responsibilities of a Market Participant purchasing Energy from the Energy Market for consumption by end-users that are located inside the New England Control Area or that is selling to buyers external to the New England Control Area include but are not limited to: (1) Submitting hourly schedules for Self-Scheduled Dispatchable Asset Related Demand; (2) Submitting Demand Bids including modifications to Demand Bids submitted by Dispatchable Asset Related Demand as described in Market Rule 1 Section III.1.10.9 (a) and (e); (3) Submitting Decrement Bids for use in the Day-Ahead Energy Market; (4) Submitting External Transaction sales to entities outside the New England Control Area as described in Market Rule 1 Sections III.1.10.7 and III.1.10.9(c). 1.3.2 Market Participants Selling into Energy Market The key scheduling responsibilities of a Market Participant that is selling Energy into the Energy Market include but are not limited to: (1) Submitting hourly schedules for Self-Scheduled Resources as provided for in Market Rule 1 Sections III.1.10.3 and III.1.10.9; (2) Submitting External Transactions purchases for delivery as described in Market Rule 1 Sections III.1.10.7 and III.1.10.9(c); (3) Submitting Supply Offers for generating CSO Resources, other than Intermittent Generating Capacity Resources or Settlement Only Resources, for supply of Energy to the Day-Ahead Energy Market and Real-Time Energy Market as described in Market Rule 1 Section III.1.10.9; (4) Submitting fixed, priced, or Up-to Congestion External Transactions into the Day-Ahead Energy Market (no wheel-through External Transactions). (5) Submitting optional Supply Offers for the supply of Energy and other services from Non-CSO Resources into the Day-Ahead Energy Market for the next Operating Day. These Supply Offers are subject to modification during and after the Re-Offer Period as described in Market Rule 1 Section III.1.10.9. Resources may also request to Self-Schedule as described in Market Rule 1 Section III.1.10.9; and (6) Submitting Increment Offers for use in the Day-Ahead Energy Market. (7) Generating CSO Resources (except Intermittent Generating Capacity Resources or Settlement Only Generators) must submit Supply Offers into the Day-Ahead Energy Market and all generating Resources may submit Supply Offers for use in the Day-Ahead Energy Market. (8) Market Participants may submit fixed, priced, or Up-to Congestion External Transactions into the Day-Ahead Energy Market (no wheel-through External Transactions). (9) Market Participants with a CSO from an Import Capacity Resource must offer External Transactions into the Day-Ahead Energy Market and Real-Time Energy Market. (10) The resulting Day-Ahead hourly schedules and Day-Ahead Prices represent binding financial commitments of the Market Participants. (11) Non-Market Participant Transmission Customers may submit Through External Transactions into the Real-Time Energy Market, including quantity changes from previously submitted External Transactions, up to one hour prior to the operating hour. 1.3.3 Market Participants wheeling Energy through the New England Control Area Market Participants purchasing Energy from outside the Energy Market and wheeling the Energy through the New England Control Area must submit External Transactions. 1.3.4 Market Participants Participating with Real-Time Demand Response and Real-Time Emergency Generation Resources 1.3.4.1 Data Requirements for Real-Time Demand Response and Real-Time Emergency Generation Resources (1) The two-day forecast of hourly demand reduction described in Market Rule 1 Section III.13.6.1.5.5 must be submitted by the offer submission deadline for the Day-Ahead Energy Market. The hourly data is not subject to re-declaration during the Operating Day. (2) The monthly forecast of the maximum monthly demand reduction for each of the next twelve months as described in Market Rule 1 Section III.13.6.1.5.6 must be submitted before the close of business on the last day of the previous month. 1.4 Non-Market Participant Transmission Customer Responsibilities Non-Market Participant Transmission Customers purchasing Energy from outside the New England Control Area and wheeling the Energy through the New England Control Area for use outside the New England Control Area must submit External Transactions to the Real-Time Energy Market. Section 2: Energy Market 2.1 Pricing Locations There is a set of Locations within the New England Control Area at which the app calculates prices. Locations include nodes on the New England Transmission System to which Generators are physically connected and all nodes at which Asset Related Demand is physically connected. All other load is priced at the Load Zone and is modeled as described in Section 2.2.2.1(12) and (13) of this manual. The app use of nodes is explained below: Nodes of several different types are used within the New England electricity markets. At the most fundamental level, an electrical node, or E-Node, is a point where two or more devices (such as a line, transformer, breaker, etc.) connect. E-Nodes represent the physical connection points of the components of the power system that are modeled in the apps network model. Generation is injected and load is withdrawn from the electrical system at E-Nodes. The apps dispatch and pricing software calculates prices at E-Nodes. Prices for E-Nodes are not publicly reported. P-Nodes are Pricing Nodes. Each P-Node is mapped to a single E-Node. P-Nodes are used to translate the physical private power system model (private in that the Market does not see this model) into a commercial or financial public model for market purposes. When multiple E-Nodes are electrically close together such that there would never be congestion between the E-Nodes (for example, multiple E-Nodes at the same voltage level within a substation), a single P-Node is sufficient to represent the price of the close E-Nodes. As a result, many E-Nodes do not have a P-Node mapped to them, as shown in Exhibit 2.1. The set of all P-Nodes is therefore smaller than the set of all E-Nodes. This is advantageous because the public financial model of the power system is able to remain relatively stable, even though the physical power system model may undergo frequent small changes.  Exhibit 2.1: Single P-Node Mapped to Multiple Close E-Nodes Certain P-Nodes are used only for modeling purposes as part of AP-Nodes (Aggregated Pricing Nodes). Prices for these P-Nodes are not published and are not public P-Nodes. For other P-Nodes that are public P-Nodes, prices are published for the Day Ahead, Real Time, and FTR markets. These public P-Nodes represent locations that may be used for the submission of Offers/Bids/FTR transactions. AP-Nodes are all public locations, and prices are published for all AP-Nodes. The price at an AP-Node is a weighted average price of the P-Nodes included in the AP-Node. The New England Hub is an example of an AP-Node. For the New England Hub, the Hub price is the arithmetic average of the prices of the P-Nodes that comprise the Hub. Load Zones are also examples of AP-Nodes. For each Load Zone, the Load Zone AP-Node Price is the load-weighted average of P-Node prices within the Load Zone. Certain generators (typically combined cycle units) and Dispatchable Asset Related Demands may have the Resource modeled as an AP-Node comprised of several P-Nodes. For these Resource AP-Nodes, the AP-Node Price is a MW-weighted average of the P-Node prices. Only the Resources AP-Node price is published, and all bidding for the Resource takes place at the AP-Node. Settlement of the Markets is based on generation injections, load withdrawals, and prices at the public AP-Nodes and public P-Nodes for which prices are publicly published. 2.2 Energy Market Business Rules 2.2.1 Bidding & Operations Time Line 10:00 a.m. Day-Ahead Energy Market submission period closes for Supply Offers, Increment Offers, Demand Bids and External Transactions. Upon Completion of the Day-Ahead Energy Market The Day-Ahead Energy Market hourly schedules, Day-Ahead Prices are posted and the Re-Offer Period begins. During this time, changes to Supply Offers and Demand Bids (for Dispatchable Asset Related Demand only) may be made in accordance with Market Rule 1 Section III.1.10.9. Priced External Transactions that do not clear in the Day-Ahead Energy Market participate in the Real-Time Energy Market based on prices submitted in the Real-Time Energy Market. Market Participants with priced External Transactions that cleared in the Day-Ahead Energy Market must modify the price component of the corresponding Real-Time Energy Market offer after the Day-Ahead Energy Market clears in order to opt out of the Real-Time scheduling priority for the Day-Ahead Energy Market cleared MW. Close of the Real-Time Energy Market Re-Offer Period The app performs a Reserve Adequacy Analysis that includes the updated Supply Offers, updated External Transactions, updated Demand Bids for Dispatchable Asset Related Demands, updated generating Resource availability information, and updated app load forecast information including deviation between the app load forecast and the sum of cleared Demand Bids and Decrement Bids utilized in the Day-Ahead Energy Market. When insufficient supply side capacity is available to meet the New England Control Area or zonal capacity requirements, the RAA identifies the app Operating Procedure No. 4 Actions needed to resolve the deficiency. This analysis could also result in the release of generating Resources that were committed in the Day-Ahead Energy Market in order to avoid a projected Minimum Generation Emergency. 5:00 p.m. The app provides individual Resource schedules developed during the initial Reserve Adequacy Analysis for non-Fast Start Generators and for priced External Transactions to affected Lead Market Participants by posting on a secure site. Throughout the Operating Day The app may also perform additional Reserve Adequacy Analyses, as necessary, based on updated app load forecasts and updated Resource availability information. The app sends out individual Resource schedule updates developed during the additional Reserve Adequacy Analyses to affected Lead Market Participants by posting on a secure site. The app may request that Resources without Capacity Supply Obligations or with energy available above their Capacity Supply Obligations voluntarily provide energy to meet reliability needs pursuant to Market Rule 1 Section III.13.6.4. 2.2.2 Market Participants Buying from Energy Market The following business rules apply to Market Participants purchasing from the Energy Market: 2.2.2.1 Demand Bids (1) Submittal of Demand Bids must be associated with a physical load that has been registered as a Load Asset. (2) A Demand Bid not associated with a Dispatchable Asset Related Demand must have a MW quantity for each hour of the Operating Day and Location specified. Price sensitive Demand Bids also must have a price specified above which the demand should not be scheduled. For all Demand Bids, other than Demand Bids associated with Asset Related Demands, the valid settlement Location is the applicable Load Zone. (3) Market Participants should not include the impact of PTF losses as part of their Demand Bids as PTF losses are accounted for on a financial basis through the Loss Component of the LMP. (4) Price sensitive Demand Bids for use in the Day-Ahead Energy Market are accepted in single bid blocks only. Up to ten bid blocks applicable to each hour of the day may be submitted per Market Participant at a specific Location. (5) Price sensitive Demand Bids must be less than or equal to the Energy Offer Cap and equal to or above the Energy Offer Floor. (6) If a Market Participant submits no Demand Bid into the Day-Ahead Energy Market for load not associated with an Asset Related Demand, then a zero MW quantity is assumed in the Day-Ahead Energy Market. (i.e., Demand Bids do not carry forward on a day-to-day basis). (7) If a Market Participant submits no Demand Bid into the Day-Ahead Energy Market for load associated with an Asset Related Demand, then the most recent previously submitted Demand Bid for a prior Day-Ahead Energy Market day other than as provided in Market Rule 1 Section III.1.10.1A(g) is assumed in the Day-Ahead Energy Market. (i.e., Demand Bids associated with Asset Related Demands carry forward on a day-to-day basis). The default Demand Bid MW quantity for an Asset Related Demand is zero. (8) Except as otherwise provided in Market Rule 1 Section III.1.10.6 for pumping demand of a pumped storage generator that does not have a Capacity Supply Obligation, Market Participants with Dispatchable Asset Related Demands must submit Demand Bids into the Day-Ahead Energy Market for such Resources with a Minimum Consumption Limit that is less than or equal to the Nominated Consumption Level specified during the Asset Registration Process. The Demand Bid must specify changes to the Maximum Consumption Limit and Minimum Consumption Limit from those submitted as part of the Resources Bid Data Offer Data to reflect the physical operating characteristics and/or availability of the Resource, except that, for a Self-Scheduled Resource, the Minimum Consumption Limit may be revised to reflect the Self-Scheduled consumption level of the Resource. Market Participants may submit up to 10 Demand Bid Blocks per day for each Dispatchable Asset Related Demand. Demand Bids from DARD Pumps must also specify changes to their Minimum Run Times, Minimum Down Times, Maximum Daily Consumption Limit, Maximum Number of Daily Starts from those submitted as part of their Offer Data to reflect their physical operating characteristics (9) Demand Bids from Dispatchable Asset Related Demand in MW amounts larger than the largest generating Resource on the system are prohibited. (10) Market Participants with Dispatchable Asset Related Demands that are Self-Scheduled Resources must submit Demand Bids for the entire operating range of the Resource between the Nominated Consumption Limit Level and Maximum Consumption Limit. (11) A Market Participant may revise its Demand Bid associated with a Dispatchable Asset Related Demand and submit it for use in the Real-Time Energy Market or it may Self-Schedule the Dispatchable Asset Related Demand with app approval as described in Market Rule 1 Section III.1.10.9. (12) For modeling purposes, the load distribution to Nodes within a Load Zone for the Day-Ahead Energy Market is based on a rolling seven-day average of historical State Estimator distribution for that Load Zone. The list of Load Zones at which Demand Bids are accepted is posted on the apps website. (13) For modeling purposes, the load distribution to Nodes within a Load Zone for the Real-Time Energy Market is the actual State Estimator distribution of loads 2.2.2.2 Decrement bids (1) Market Participants may submit up to fifty Decrement Bid Blocks per hour for use in the Day-Ahead Energy Market at any Location for which an LMP is calculated. (2) It is not required that physical load exists at the Location that is specified in the Decrement Bid. (3) Decrement Bids are only applicable in the Day-Ahead Energy Market. (4) Decrement Bids must be less than or equal to the Energy Offer Cap and be equal to or above the Energy Offer Floor. 2.2.2.3 External Transactions (Exports) (1) External Transactions not properly submitted via EES are rejected. The Market Participant is notified of the reason for rejection and the Market Participant may then take action to submit a new External Transaction. (2) External Transaction data applicable to the Day-Ahead Energy Market does not carry forward for use in the Real-Time Energy Market. (a) A Real-Time Energy Market External Transaction must be submitted for all External Transactions that were designated as applicable in the Day-Ahead Energy Market if the Market Participant wants the Energy to be considered in the Real-Time Energy Market. (b) A single External Transaction transmittal can contain information for both the Day-Ahead Energy Market and Real-Time Energy Market. (c) Market Participants with External Transactions that modify their prices in Real-Time for transactions that cleared in the Day-Ahead Energy Market or that do not clear in the Day-Ahead Energy Market participate in the Real-Time Energy Market based on prices submitted in the Real-Time Energy Market. For purposes of Real-Time scheduling priority, such transactions will be treated as if they did not clear in the Day-Ahead Energy Market. (3) Market Participants should not include the impact of PTF losses as part of their External Transactions as PTF losses are accounted for on a financial basis through the Loss Component of the LMPs. (4) Up-to Congestion External Transactions are supported in the Day-Ahead Energy Market only and may not be submitted at less than $.01/MWh or more than $25/MWh. (5) Priced External Transaction sales for the Day-Ahead and Real-Time Energy Markets must be offered at less than or equal to the Energy Offer Cap and equal to or above the Energy Offer Floor. (6) A Market Participant may revise the price component of its priced External Transaction for the Real-Time Energy Market during the Re-Offer Period. (7) External Transaction sales that comply with the conditions described in Market Rule 1 Section III.1.10.7 (f) may qualify for treatment that improves the transactions likelihood of flowing in Real-Time through the apps commitment of Local Second Contingency Protection Resources and improved scheduling and curtailment priorities, as delineated in Market Rule 1 Section III.1.10.7 (g) and app Open Access Transmission Tariff Section II.44. Export Transaction sales receiving this treatment will be assessed a share of certain NCPC charges and Reserve charges as explained in Market Rule 1 Sections III.1.10.7 (h), III.9.9, III.10.3 and III.F.3.3. 2.2.3 Market Participants Selling into Energy Market The following business rules apply to Market Participants selling into the Energy Market: 2.2.3.1 Generating Resources (1) Submittal of Supply Offers must be associated with a registered Generator Asset. (2) Supply Offers must be less than or equal to the Energy Offer Cap and equal to or above the Energy Offer Floor. (3) Submitting a generating Resources Supply Offer in MW amounts greater than the largest generating Resource on the system is prohibited. (4) The set of Supply Offers last submitted for each Generator shall remain in effect for each day until specifically superseded by subsequent Supply Offers except as provided in Market Rule 1 Section III.1.10.1A (g). (5) During and after the Re-Offer Period, a Market Participant may revise the Supply Offer of a generating Resource or request to Self-Schedule the generating Resource as described in Market Rule 1 Section III.1.10.9. (6) Supply Offers for Self-Scheduled generating Resources will be used by the app for scheduling available Resources in the Day-Ahead Energy Market for the energy between their Economic Minimum Limits and their Economic Maximum Limits. (7) Fast Start Generators may be scheduled in the Day-Ahead Energy Market. However, the decisions concerning actual operation of Fast Start Generators by the app during the Operating Day are made based upon economic dispatch in the Real-Time Energy Market. (8) Generating Resources must specify a Minimum Run Time to be used for scheduling purposes that does not exceed 24 hours. Generating Resources with Minimum Run Times that require that they run for more than 24 hours may Self-Schedule to remain on-line. (9) A Market Participant may change the Supply Offer of a generating Resource as provided in Market Rule 1 Section III.1.10.9. (10) Market Participants may submit, for any Resource for which a Supply Offer is submitted, its Offered CLAIM10 and Offered CLAIM30. (11) A Supply Offer for a generating Resource that is accepted but not cleared for the Day-Ahead Energy Market automatically carries over for use in the Real-Time Energy Market unless modified pursuant to Market Rule 1 Section III.1.10.9, except as noted below: (a) Non-CSO Generating Resources that do not clear in the Day-Ahead Energy Market, have not been assigned a Forward Reserve Obligation in at least one hour of the next Operating Day, are not enrolled in the Open Access Transmission Tariff's Schedule 2 VAR program, and have not been designated as Supplemental Capacity Resources for the next Operating Day are unavailable for commitment by the app for the next Operating Day, except with respect to requests for energy from Non-CSO Resources pursuant to Market Rule 1 Section III.13.6.4. (b) Market Participants may request to Self-Schedule these Non-CSO Resources in order to participate in the Real-Time Energy Market. The Resource will be dispatchable in Real-Time up to the offered Economic Maximum Limit. (12) Only one Supply Offer for each generating Resource is in effect at any given time during an Operating Day. (13) A Supply Offer must include operating limits, which must be based on the following: (a) Emergency Minimum Limit is based on the physical capability and design of the generator and should not change on a day to day basis, except as required by the impact of environmental factors, including ambient temperature, emission limits and other operating permit requirements and is defined in Section I.2.2 of the Tariff. (b) Economic Minimum Limit is as defined in Section I.2.2 of the Tariff. (c) Economic Maximum Limit as defined in Section I.2.2 of the Tariff is no less than the greater of the Capacity Supply Obligation of the generating Resource or its Economic Minimum Limit to the extent the Resource is available. (d) Real-Time High Operating Limit as defined in Section I.2.2 of the Tariff. For Market Participants submitting an Economic Maximum Limit value for a Resource as part of a Day-Ahead Energy Market offer, the Real-Time High Operating Limit is provided to app through each Resources Day-Ahead Supply Offer data and must be re-declared to reflect changes in physical operating characteristics and operating permit limitations. (e) If Real-Time High Operating Limit changes at any time after the initial data values were communicated to the app, the Designated Entity must re-declare the data values as follows: (i) Re-declarations made on the day prior to the Operating Day must be called into the Forecaster Desk. (ii) Re-declarations made during the Operating Day must be called into the Control Room Generation Desk. (14) For Limited Energy Resources, a Market Participant shall submit into the Day-Ahead Energy Market, as part of the normal Supply Offer for the generating Resource, an estimate of the total Energy that unit is capable of producing for the Operating Day. In Real-Time, the Market Participant can manage the use of energy from any portion of a Limited Energy Resource through the use of limited energy hourly maximum levels for the associated Limited Energy Resource. 2.2.3.2 Increment Offers (1) A Market Participant may submit on an Increment Offer up to fifty Blocks per hour for use in the Day-Ahead Energy Market at any Location for which an LMP is calculated. It is not required that physical generation or load exists at the Location that is specified in the Increment Offer. (2) Increment Offers are only applicable in the Day-Ahead Energy Market. 2.2.3.3 External Transactions (Imports) (1) A Market Participant with an Import Capacity Resource must submit priced or fixed External Transactions that meet the requirements of Market Rule 1 Section III.13.6.1.2 into both the Day-Ahead Energy Market and the Real-Time Energy Market. (2) External Transactions not properly submitted via EES are rejected. The Market Participant is notified of the reason for rejection and the Market Participant may then take action to submit a new External Transaction. (3) External Transaction data applicable to the Day-Ahead Energy Market does not carry forward for use in the Real-Time Energy Market. (a) A Real-Time Energy Market External Transaction must be submitted for all External Transactions that were designated as applicable in the Day-Ahead Energy Market if the Market Participant wants the Energy to be considered in the Real-Time Energy Market. (b) A single External Transaction transmittal can contain information for both the Day-Ahead Energy Market and Real-Time Energy Market. (c) Market Participants with External Transactions that modify their prices in Real-Time for transactions that cleared in the Day-Ahead Energy Market or that do not clear in the Day-Ahead Energy Market participate in the Real-Time Energy Market based on prices submitted in the Real-Time Energy Market. For purposes of Real-Time scheduling priority, such transactions will be treated as if they did not clear in the Day-Ahead Energy Market. (4) Market Participants should not include the impact of PTF losses as part of their External Transactions as PTF losses are accounted for on a financial basis through the Loss Component of the LMPs. (5) Priced External Transaction purchases submitted for use in the Day-Ahead Energy Market shall specify MW quantity, External Node, and the price below which the transaction should not be scheduled. (6) Priced External Transaction purchases submitted for use in the Real-Time Energy Market shall specify MW quantity, External Node, and the price below which the transaction should not be scheduled. (7) Up-to Congestion External Transactions are supported in the Day-Ahead Energy Market only and may not be offered or bid at less than $.01/MWh or more than $25/MWh. (8) A Market Participant may revise the price component of its priced External Transaction for the Real-Time Energy Market during the Re-Offer Period. (9) Priced External Transactions must be less than or equal to the Energy Offer Cap and equal to or above the Energy Offer Floor. (10) External Transaction entries greater than 999 MW are prohibited. 2.2.3.4 Demand Response Resources The app will include Real-Time Demand Response Resources and the Day-Ahead Demand Reduction Offers of Real-Time Demand Response Assets in the current operating plan for the Operating Day. Real-Time Demand Response Resources and Real-Time Emergency Generation Resources will be dispatched as provided in Market Rule 1 Section III.13. Real-Time Demand Response Assets will be scheduled as provided in Market Rule 1 Appendix III.E1. 2.2.4 Non-Market Participant Transmission Customers The following business rules apply to Transmission Customers wheeling energy through the app: (1) Non-Market Participant Transmission Customers may only submit Through External Transactions into the Real-Time Energy Market. (2) A Transmission Customer should not include the impact of transmission losses as part of its Through External Transaction submitted for use in the Real-Time Energy Market as transmission losses are accounted for on a financial basis through the Loss Component of the LMP. (3) Through External Transactions must be submitted to the Real-Time Energy Market as fixed, they may not be priced. 2.2.5 Designation as Real-Time Reserve and Declaration of Limited Energy Resource Status The following business rules apply to designation of available Resources as Real-Time Reserve and declarations of hourly profiles for Limited Energy Resources. (1) During the various Reserve Adequacy Analyses, the app may limit its dependence on off-line Fast Start Generators to provide Operating Reserve in order to maintain reliable operational standards. Such limits shall be based on past performance of these units. (2) Available Resources may be designated as Real-Time Operating Reserve if they meet the following criteria: The Resource must be following Dispatch Instructions; The Resource must be on-line or be an off-line Fast Start Generator or Dispatchable Asset Related Demand with CLAIM10 and/or CLAIM30 values greater than zero; TheA generating Resource must have excess capacity not being utilized to meet the energy needs of the system (i.e. be operating below its Economic Maximum Limit)or have agreed in advance to allow the app to curtail self-scheduled pumping load; A DARD Pump must be online and the app must be able to reduce or curtail its load to maintain reliability. The applicable MW of the Resource are subject to a Capacity Supply Obligation or have been voluntarily offered for Real-Time dispatch; and The generating Resource must not have been designated as constrained in order to manage transmission congestion. (3) For Limited Energy Resources, the Lead Market Participant may declare an hourly profile of economic dispatch maximums that can be below the Economic Maximum Limit specified in the Offer Data. These hourly limits can be set to a Day-Ahead hourly schedule or be redeclared subject to Market Rule 1 and app business procedures restrictions. The Lead Market Participant can request that the Real-Time dispatch limit hourly scheduling to the lower dispatch maximum for the purpose of preserving a limited supply of Energy for future hours of the Operating Day. The app will continue to designate the Operating Reserve available above the lower limit up to the Economic Maximum Limit requested by the Market Participant and may activate that Operating Reserve as it deems appropriate to maintain reliability. Market Participants may request a change in the hourly generation schedule of a Limited Energy Resource by calling the app system operators at least 30 minutes prior to the time of the desired change. If the app can accommodate the schedule change in less than the 30-minute notification period, the change may be granted earlier. 2.2.6 Technical Rules (1) A valid Supply Offer consists of the following elements: For generating Resources, a valid Supply Offer consists of the following inputs. The default values are: Day-Ahead Energy Market switch is check or yes (1). Real-Time Energy Market switch is check or yes (1). Use offer slope switch is square box or no (0). Condense available switch is blank or no (0). Hourly Start-Up Fee and No-Load Fee is zero. Fuel type default is lower priced fuel for dual fuel Resources Must contain an Emergency Minimum Limit and an Economic Maximum Limit of at least one MW. Hourly Economic Max/Min and Emergency Min are the unit level economic and emergency MW limits. Minimum Down Time, Minimum Run Time, Start-Up Times, and Notification Times are zero. Maximum Run Time and maximum number of starts per week are infinity. Blocks (price and quantity of energy) for each hour of the Operating Day. The default for incremental offer curve data is $0. The curve is extended up using zero slope from the last incremental point on the curve if the offer curve is of inadequate length to dispatch and/or price operating capability. Offered CLAIM10 MW. Default value is zero MWs. Offered CLAIM30 MW. Default value is zero. Manual Response Rates (MRR) for associated MW ranges. (2) Valid Demand Bids, price sensitive and fixed, consist of the following items: MW, with a default value of zero MW. Location (Load Zone). Price above which demand should not be scheduled (for price-sensitive Demand Bids). (3) Valid Demand Bids for Asset Related Demand consist of the following items: Hourly Maximum Consumption Limit and hourly Minimum Consumption Limit (for non-dispatchable Asset Related Demand, Minimum Consumption Limit is equal to Maximum Consumption Limit). Monotonically decreasing bid curve for Blocks between Minimum Consumption Limit and Maximum Consumption Limit for Dispatchable Asset Related Demand (non-dispatchable Asset Related Demand is considered fixed demand at the Node). Ramp rate for associated MW ranges for Dispatchable Asset Related Demand. CLAIM10 for Dispatchable Asset Related Demand. Default value is zero MW. CLAIM30 for Dispatchable Asset Related Demand. Default value is zero MW. (4) Valid Demand Bids for DARD Pumps consist of (2) and (3) above plus the following items: Minimum Run Time (not to exceed one hour). Default is one hour; Minimum Down Time (not to exceed one hour). Default is one hour; Maximum Daily Consumption. Default is unlimited. Maximum Number of Daily Starts. Default is 12. 2.2.7 Major Modeling Assumptions Fixed External Transactions, priced External Transactions, Supply Offers, Increment Offers, Decrement Bids and Demand Bids are modeled in the Day-Ahead Energy Market technical software. Up-to Congestion External Transactions are not modeled in the Day-Ahead Energy Market commitment, but are handled in the Day-Ahead Energy Market dispatch. The app does not commit additional generation in the Day-Ahead Energy Market to support Up-to Congestion External Transaction sales and does not reduce generation commitment in the Day-Ahead Energy Market to account for Up-to Congestion External Transaction purchases. 2.2.8 Reserved 2.2.9 Reserved 2.2.10 Emergency Conditions in the Real-Time Energy Market 2.2.10.1 Capacity Deficient Conditions The app will post as soon as practicable, an Emergency Condition warning (in this case Master Local Control Center Procedure #2 and/or OP-4 forecast or actual implementation) on the apps web site, as soon as Emergency Conditions or anticipated Emergency Conditions are identified by the app. Please see app Operating Procedure No. 4 for a description of app actions during capacity deficient conditions. When scheduling External Transactions for the next scheduling interval of an Operating Hour, if the expected net schedule of all External Transactions, coupled with the expected load consumption and output of available generating units, will result in a capacity deficiency condition, the app shall determine the export amount of External Transactions that can be reliably scheduled without entering a capacity deficient condition and, as a result, will restrict the upcoming scheduling of Real-Time Energy Market External Transaction exports that have not cleared the Day-Ahead Energy Market, to the extent required. An External Transaction referencing a Generator whose associated generating Resource has capacity not subject to a Capacity Supply Obligation shall be treated in accordance with Market Rule 1 Section III.1.10.7 (i). If Real-Time Energy Market External Transaction exports need to be restricted as described above to prevent the capacity deficiency, then the app will issue a notice on the app web site. If the restriction of Real-Time Energy Market External Transaction exports that have not cleared the Day-Ahead Energy Market does not prevent the capacity deficiency condition, app Operating Procedure No. 4 will be implemented. When app Operating Procedure No. 4 has been implemented, Real-Time Energy Market External Transaction exports that have cleared the Day-Ahead Energy Market will continue to be scheduled until such time as Market Participant Emergency Energy Transactions are not available to resolve the capacity deficient condition. An External Transaction referencing a Generator whose associated generating Resource has capacity not subject to a Capacity Supply Obligation shall be treated in accordance with Market Rule 1 Section III.1.10.7 (i). To the extent restrictions in scheduling External Transactions are required as set forth above, the process for reducing all Real-Time Energy Market External Transaction exports is described in app Operating Procedure No. 9 Appendix B. The dispatch of Real-Time Demand Response Resources may be increased, decreased or cancelled in Real-Time from the amount forecast in the initial Current Operating Plan, and Real-Time Emergency Generation Resources may be dispatched in Real-Time when app Operating Procedure No. 4 has been declared. 2.2.10.2 Minimum Generation Conditions During the Operating Day, the app will issue Minimum Generation Emergency warnings, as needed, if the app projects the difference between: the sum of projected load consumption; and the sum of the expected net schedule of all External Transactions and all on-line generating unit Economic Minimum Limits; to be equal to or less than the threshold MW amount set forth in apps Control Room Operating Procedures (CROP.25005 Minimum Generation), either with regard to a sub-region or the New England Control Area, as applicable. When scheduling External Transactions for the next scheduling interval within an operating hour where a Minimum Generation Emergency Warning has been issued, the app will determine if scheduling External Transaction imports that have not cleared in the Day-Ahead Energy Market will cause the threshold Minimum Generation Emergency margin to be reached (using the equation from the Control Room Operating Procedure referenced above). If so, then the app will restrict the upcoming scheduling of Real-Time Energy Market External Transaction imports that have not cleared the Day-Ahead Energy Market. This process is also applicable if the Minimum Generation Emergency Warning occurs within a scheduling interval. The process for reducing these External Transaction purchases is described in app Operating Procedure No. 9. If the app declares a Minimum Generation Emergency pursuant to Market Rule 1 Section III.2.5(c), the following steps will be taken to maintain system reliability: (1) The app will set all LMPs to the Energy Offer Floor within the affected sub-region(s) or the New England Control Area, as applicable. (2) Based on price, generating Resources will be subject to Dispatch Instructions from the app to reduce generation down to Emergency Minimum Limits and all External Transaction purchases that cleared in the Day-Ahead Energy Market will be subject to reduction. Such reductions of generation and External Transactions will be applied on a 50/50 basis until supply and demand are matched or the capability of either generating Resources or External Transactions to reduce is exhausted. Required reductions will then be taken on the remaining generating Resources or External Transaction purchases as needed. The reduction of External Transaction purchases that cleared in the Day-Ahead Energy Market will occur as described in app Operating Procedure No. 9. (3) If the actions in Step (2) are not sufficient to match supply to demand, the app will utilize all available information available to it, including but not limited to Minimum Run Times or Minimum Down Times and expected capacity conditions for the next Operating Day, recognizing the Pool-Scheduled Resource vs. Self-Scheduled Resource priority, in issuing de-commitment orders. (4) LMPs will remain at the Energy Offer Floor until the app cancels the Minimum Generation Emergency. When the app cancels a Minimum Generation Emergency and restores the affected generating Resources Economic Minimum Limits, the Unit Dispatch Software (UDS) will issue DDPs to dispatchable generating Resources operating below their Economic Minimum Limits to move to their Economic Minimum Limits. For non-dispatchable generating Resources, UDS will not issue DDPs to move from below their Economic Minimum Limits to their Economic Minimum Limits. The non-dispatchable generating Resource is required to move to its Economic Minimum Limit on its own initiative. Generating Resources moving up to their Economic Minimum Limits will not be determined to be failing to follow Dispatch Instructions. Failure to move to Economic Minimum Limit after a Market Participant is notified of the situation by the app for any generating unit operating below Economic Minimum Limit as a result of a Minimum Generation Emergency may result in the app entering a redeclaration of the generating units Economic Maximum Limit to match its current output level. Section 3: Scheduling 3.1 Treatment of Certain Resources 3.1.1 Local Second Contingency Protection Resources When establishing operating schedules, the app chooses (or flags) which Resources must be operated for local second contingency protection. The app will also indicate, in an auditable log, why each Resource was chosen. See the app Manual for Market Rule 1 Accounting, M-28 and Market Rule 1 Appendix III.F for a description of the settlement treatment associated with Local Second Contingency Protection Resources. 3.1.2 Special Constraint Resources In order to maintain area reliability, Transmission Owners or distribution companies may request the app to change the commitment of a Resource or the incremental loading on a previously committed Resource to provide relief for constraints not reflected in the apps systems for operating the New England Transmission System or its operating procedures. Requests will normally be made to the app via the appropriate Local Control Center unless Emergency Conditions justify immediate communications with the Resources. Such out of merit operation of units for any reliability purposes to provide relief for constraints (thermal, voltage or stability) not reflected in the System Operators systems or procedures will result in the Resource(s) being designated as a Special Constraint Resource (SCR). When a unit would not be operating above its Economic Minimum but for the request of the Transmission Owner or distribution company, it shall be flagged as SCR for Net Commitment Period Compensation under Market Rule 1 Appendix III.F. 3.1.3 Self-Scheduled Dispatchable Asset Related Demand Resources Market Participants can choose to Self-Schedule their Dispatchable Asset Related Demand in the Day-Ahead Energy Market or can choose to allow the app to schedule their demand in the Day-Ahead Energy Market based on the Demand Bids submitted. The Market Participant indicates the desired level of Self-Scheduled MW by submitting a Minimum Consumption Limit equal to the amount of Self-Scheduled MW. Subsequent to the Day-Ahead Energy Market clearing, any Dispatchable Asset Related Demand may choose to Self-Schedule or submit revised Demand Bids as provided in Market Rule 1 Section III.1.10.9. 3.2 External Transactions External Transactions are requested through the Enhanced Energy Scheduler (EES) application. Requests for External Transactions must be submitted before specific deadlines and contain all required data. Additional information on External Transactions can be found in app Operating Procedure No. 9 - Scheduling and Dispatch of External Transactions (OP-9) and Open Access Transmission Tariff Section II.44. 3.2.1 External Transaction Submission Deadlines (1) External Transaction requests may be submitted as early as 10 days prior to the first Operating Day of the requested schedule. External Transactions shall have a minimum duration of one hour and a maximum duration of one month. (For example, a month-long transaction might run from February 21 to March 20, from March 21 to April 20 or from March 1 to March 31.) (2) To be considered in the Day-Ahead Energy Market, External Transactions must be submitted or modified via EES to the app by the offer submission deadline for the Day-Ahead Energy Market and designated as being applicable in the Day-Ahead Energy Market. External Transactions must be designated as fixed, priced or Up-To Congestion. (3) Priced Real-Time External Transactions must be submitted in accordance with Market Rule 1 Section III.1.10.7 and may be revised as provided in Market Rule 1 Section III.1.10.9(c) to be considered in the Real-Time Energy Market. 3.2.2 General Information (1) Transmission reservations, where applicable, will be subject to transmission charges, as appropriate, whether or not they are used to support Real-Time External Transactions. (2) External Transactions are subject to the apps ramping rules. For a description of the ramp rules, see Section 3.2.3 of this manual. (3) The app does not accept Supply Offers associated with Resources committed to supply Operating Reserve to another Control Area. (4) The app will not schedule net interchange on a given external interface to levels that exceed the forecasted transfer limit at the External Node. 3.2.3 Ramps The app will consider its ability to schedule Real-Time External Transactions on a system wide basis for each scheduling interval. The External Transactions scheduled in the current interval will be evaluated against the expected External Transactions in future scheduling intervals. If the system wide net interchange differs between the two Real-Time scheduling intervals by more than 500 MW, the app will review and resolve any ramp issues. 3.2.4 EES Data Requirements 3.2.4.1 Day-Ahead Energy Market The following information is submitted to the app via the EES for Day-Ahead External Transactions: (1) Valid transaction path (2) External Node(s), and internal Node, if required (3) Start date and end date (4) Start time and end time (5) Requested MW value, expressed in whole megawatts (MW) and must be stated in terms of the MW quantity to be received at or delivered to the balancing area boundary (6) Price associated with the transaction, if the transaction is a priced External Transaction (7) Congestion price associated with the transaction, if the transaction is an Up-to Congestion External Transaction (8) Market Participants submitting External Transactions into the Day-Ahead Energy Market are not required to include transmission service information or e-Tag information. 3.2.4.2 Real-Time Energy Market Transmission Customers must keep the app informed of all External Transactions into, out of and through the New England Control Area. The following information is submitted to the app via the EES for Real-Time External Transactions: (1) Valid transaction path (2) Identity of associated external interface(s) associated with the External Transaction. (3) Start date and end date (4) Start time and end time (5) Requested MW value, expressed in whole megawatts (MW) and must be stated in terms of the MW quantity to be received at or delivered to the balancing area boundary (6) Price associated with the transaction, if the transaction is a priced External Transaction (7) Special exceptions associated with the transaction, as appropriate (available exceptions are listed in Table 3.1) ExceptionDescriptionCommentImport ResourceMarket Participants with an Import Capacity Resource with a Capacity Supply Obligation must use this exception to notify app that the transaction is backing an Import Capacity Resource.Must reference the Import Capacity Resource IDFlex ReservationApplicable only to Market Participants submitting priced transactions backing Import Capacity Resources over interfaces where advance reservations are required. Checking this flag allows the user to link an OASIS reservation, and e-Tag, up to one hour before the start of the transaction. User must also reference the Import Resource exception.Must reference the Import Capacity Resource IDNon-Capacity Supply Obligation ExportMarket Participants must reference this exception for transactions to be considered under Market Rule 1 Section III.1.10.7 (i) during system-wide capacity deficient conditions.Must reference the numerical Asset ID LSCC Export (Capacity Export Through Import Constrained Zone or FCA Cleared Export Transaction)When this is selected by Market Participants that have bid and cleared appropriately in the FCA and submitted the transaction in accordance with Market Rule 1 Section III.1.10.7 (f) i or ii, Participant is requesting that the transaction be considered in local second contingency commitment and will be allocated a share of certain costs as defined in Market Rule 1 Section III.1.10.7 (h). Transactions with this exception are considered supported in Real-Time scheduling as defined in Open Access Transmission Tariff Section II.44. Note: Market Participant must also reference Non-Capacity Supply Obligation Export to be considered under Market Rule 1Section III.1.10.7(i)Must reference the numerical Asset ID backing the FCA de-list bidUnconstrained Export (Same Reserve Zone or Unconstrained Export Transaction) When this option is selected and the referenced generating Resource meets criteria in Market Rule 1 Section III.1.10.7 (f) iii or iv, the transaction is considered supported in Real-Time scheduling as defined in Open Access Transmission Tariff Section II.44. Note: Market Participant must also reference Non-Capacity Supply Obligation Export to be considered under Market Rule 1 Section III.1.10.7 (i).Must reference the numerical Asset ID Excepted TransactionWhen this is selected by Market Participants with active items in Open Access Transmission Tariff Section II Attachment G-3 and submitted in accordance with Open Access Transmission Tariff Section II.44 (a), special priority is assigned in real-time scheduling.There are currently no active items in Attachment G-3 Generation Information SystemUsed to indicate transaction is associated with Generation Information System Must contain a commentEET EmergencyWhen emergency transactions are requested by app-NE, allows user to submit priced transactions within the operating day.Does not require a commentNew Brunswick Security Energy TransactionsWhen New Brunswick Security Energy Transactions are requested by app-NE, allows user to submit priced transactions within the operating day.Must contain a comment NB is the suggested valueGrandfatheredWhen this is selected by Participants with active items in Open Access Transmission Tariff Section II Attachment H and submitted in accordance with Open Access Transmission Tariff Section II.44 (a), special priority is assigned in Real-Time scheduling.Must reference MEPCO Grandfathered Transmission Service Agreements (MGTSA); user must also link a valid associated OASIS reservationTable 3.1: Available Exceptions Associated with External Transactions (8) Advance purchase of transmission service on the app OASIS is not required for purchase, sale or through External Transactions. (9) For a Real-Time priced External Transaction supporting an Import Capacity Resource on an interface where an advance transmission reservation is required that has a special exception of Flex Reservation, the Market Participant must submit a valid e-Tag and the associated non-PTF transmission service reservation(s) by one hour before the operating hour in order to be considered for Real-Time dispatch. (10) For all other External Transactions, the associated non-PTF transmission service reservation, if applicable, and a valid e-Tag must be identified and must be provided at the time of the Real-Time Energy Market submission. 3.2.5 External Transaction Requests Upon submittal of an External Transaction to the Real-Time Energy Market, the app logs the request and performs automated validity and manual verification tests. If an External Transaction does not pass the automated verification process, it is assigned a status of Pending Action. The Transmission Customer is notified of the validation failure and the Transmission Customer may then take action to resubmit the transaction within the appropriate submission deadlines. Manual administrative action to review transactions in a status of Pending Action is not taken, except for actions taken on specific priced Real-Time External Transactions that have been submitted in support of an Import Capacity Resource. Once External Transactions pass the automated verification, they are assigned a status of Pre-Approved and the app performs manual administrative tests to establish the final status of the transaction. Real-Time External Transactions that pass all of the preceding tests will have a status of Approved. If the requested Real-Time External Transaction fails any of the preceding tests, the status will be set to Denied. The app will inform the Market Participant or Transmission Customer that the External Transaction request has been denied and the reason for the denial. 3.2.6 app Emergency Energy Purchases during Emergency Condition Consistent with Market Rule 1 Section 4 and upon implementation of app Operating Procedure No. 4 allowing the dispatch of Emergency Energy Purchases, the app may purchase available Energy from any Market Participant (as emergency) that is available up to the amount required or until there is no more available in accordance with Section VII of app Operating Procedure No. 9 Scheduling and Dispatch of External Transactions (OP-9) and the following: (1) The Market Participant is responsible for delivery (i.e., securing all necessary transmission service) of the Emergency Energy to the New England Control Area. This includes applicable and appropriate transmission service reservations over the non-PTF New England external interfaces. (2) The app will provide at least 60-minutes notice before the Emergency Energy is anticipated to be required by posting the notice provided for in Section VII of app Operating Procedure No. 9 Scheduling and Dispatch of External Transactions (OP-9). (3) Once the app posts the request for Emergency Energy purchases, the app will allow submission of Emergency Energy offers from Market Participants via the EES software and such offers may not exceed the Energy Offer Cap. 3.2.7 app Purchases of New Brunswick Security Energy Consistent with Market Rule 1 Section III.3.2.6A and app Operating Procedure No. 9 allowing the dispatch of New Brunswick Security Energy purchases, the app will purchase available Energy from any Market Participant up to the amount required or until there is no more available in accordance with Section VIII of app Operating Procedure No. 9 Scheduling and Dispatch of External Transactions (OP-9) and the following: (1) The Market Participant is responsible for delivery (i.e., securing all necessary transmission service) of the New Brunswick Security Energy Transaction to the New England Control Area. This includes applicable and appropriate transmission service reservations over the non-PTF New England external interfaces. (2) When possible, the app will provide notice before New Brunswick Security Energy is anticipated to be required by posting on the apps web site a message stating that the app anticipates requiring New Brunswick Security Energy purchases. (3) Once the app posts a request for New Brunswick Security Energy purchases, the app will allow submission of External Transactions flagged as New Brunswick Security Energy Transaction offers from Market Participants via the EES software and such offers may not exceed the Energy Offer Cap. (4) New Brunswick Security Energy Transactions from Market Participants scheduled by the app are not eligible to set the Real-Time LMP. Market Participants are paid the higher of their offer prices or the applicable External Node LMP for Security Energy Transaction purchases accepted by the app, with amounts paid accounted for as provided in the app Manual for Market Rule 1 Accounting, M-28. . Revision History Approval Approval Date: November 1, 2002 Effective Date: March 1, 2003 Revision History Revision: 1 - Approval Date: February 5, 2003 Section No. Revision Summary 1.2.2 (4)..Deletes the forecast of Day-Ahead LMPs from the posted pre-dispatch schedule report. 2.5.2 (1), 2.5.3 (1) & 2.5.6 (3)..Corrects problems discovered during Market Trials by adding language to the data verification section to have the app review Demand Bids, Supply Offers, Increment Offers and Decrement Bids in the Day-Ahead Energy Market for errors and to provide for app revision of certain Demand Bids and Supply Offers after discussion with the submitting Participant. 2.5.2 (14)Clarifies that the Hub is not a valid Location for Demand Bids. 2.5.9Adds a better explanation of the calculation of the three components of the LMPs. 3.2.1 (10) & 3.2.7 (4)..Clarifies the calculation of Opportunity Costs in the Regulation Market. Revision: 2 - Approval Date: April 4, 2003 Section No. Revision Summary 1.1...Adds language stating that Resources without Electronic Dispatch Capability (EDC) must Self-Schedule in the Day-Ahead Energy Market. 2.2...Clarifies that ICAP Resources without EDC must meet the requirement to offer in the Day-Ahead Energy Market through a Self -Schedule. 2.5.3 (3)..Adds language stating that ICAP Resources without EDC must Self-Schedule in the Day-Ahead Energy Market. 2.5.3 (9)..Replaces the word in with the word for in the description of Supply Offers for Generators with minimum run times in excess of 24 hours. 2.5.9.2 (2)(b)..Clarifies that Generators on Regulation are excluded from the calculation for flagging units for failure to follow Dispatch Instructions. 6.3.4Clarifies that only Resources with EDC may submit Supply Offers in the Day-Ahead Energy Market. Revision: 3 - Approval Date: May 2, 2003 Section No. Revision Summary 2.5.10(1)(a).Revise treatment of stale data or program failure to apply to cases where 11 intervals or less are affected and to explain when the next successful interval will be used in lieu of the last successful interval. Revision: 4 - Approval Date: June 26, 2003 Section No. Revision Summary 2.5.9....Adds a description of a mathematical condition encountered by the software in the calculation of Real-Time Nodal Prices in rare instances known as dual degeneracy to the description of the calculation of Real-Time Nodal Price. The addition of Section 2.5.16.3 is contingent upon FERC acceptance of corresponding revisions to Market Rule 1 filed by the app on May 15, 2003. 2.5.16.3...Adds a new subsection that adds Reserve Shortage Condition provisions to the Manual, including: when a Reserve Shortage Condition will be declared, notification to the market by the app, pricing implications, and the calculation of Reserve Shortage Opportunity Costs to be recovered pursuant to app Manual for Market Rule 1 Accounting, M-28. Revision: 5 - Approval Date: October 3, 2003 Section No. Revision Summary 8.1...Language is added to conform Manual 11 to the recent change in notice requirements announced pursuant to Market Rule 1 for changes to Self-Schedules for certain internal generating Resources to 30 minutes. Revision: 6 - Approval Date: February 20, 2004 Section No. Revision Summary 3.2.1(3)...Adds language clarifying that the information must be supplied prior to the close of the Regulation Market. 3.2.1(4)...Revises the section to state that unit regulating status for units available for Energy in the Day-Ahead Energy Market may be changed from available to unavailable after the Regulation Market closes. 3.2.1(7)...Revises the treatment of units that were unavailable in the Day-Ahead Energy Market and become available later so that they may Self-Schedule for Regulation only if they are available and submit the Self-Schedule prior to the close of the Regulation Market. 3.2.1(10).Limits requests by Limited Energy Generators to Self-Schedule for Regulation (and the associated Redeclaration of Regulation Limits and Regulation Capacity to be consistent with the LEG MWh limit) to those submitted prior to the close of the Regulation Market. Revision: 7 - Approval Date: March 12, 2004 Section No. Revision Summary 1.2.2(2)(b) & 2.1...Adds language indicating that all offers and bids and External Transactions may clear in the Day-Ahead Market in partial MW quantities. 2.3...Adds language indicating that External Transactions are scheduled and settled in whole MW quantities in the Real-Time Energy Market. Revision: 8 - Approval Date: May 7, 2004 Section No. Revision Summary 3.2.1(3)(b)..Clarifies that Regulation Capability represents the amount of movement that can be achieved within 5 minutes while providing Regulation. 3.2.1(9)...This subsection is deleted. Revision: 9 - Approval Date: November 5, 2004 Section No. Revision Summary These revisions shall cease to be in effect after April 15, 2006 (Sunset Provision). 1.1...Clarifies that the timeline for scheduling activities in Exhibit 1.1 applies under normal conditions and adds Exhibit 1.1.A to describe the scheduling timeline when a Cold Weather Event is declared pursuant to OP-20. 1.2.2(5)...Replaces 12:00 with the close of the Day-Ahead Energy Market bid/offer period. 2.3...Replaces noon with the close of the Day-Ahead Energy Market bid/offer period. 2.5.1Divides the last sentence of the paragraph into two sentences for clarity. 2.5.7(2)...Replaces 12:00 deadline with the close of the Day-Ahead Energy Market bid/offer period. 3.1...Adds under normal conditions to the description of the Regulation Market Timeline. Adds a new Exhibit 3.1.A to illustrate the Regulation Market Timeline when a Cold Weather Event is declared pursuant to OP-20. 3.2.4Replaces 12:00 with the close of the Day-Ahead Energy Market bid/offer period. 6.4.1(2)&(3)...Replaces 12:00 with the close of the Day-Ahead Energy Market bid/offer period. 6.4.7Replaces 12:00 with the close of the Day-Ahead Energy Market bid/offer period. Revision: 10 - Approval Date: June 28, 2004 Section No. Revision Summary Entire Manual revised to reflect RTO terminology and to reflect the Market Rule 1 and Transmission Markets and Service Tariff provisions filed with the FERC (e.g., the elimination of Internal Point-to-Point Transmission Service). Revision: 11 - Approval Date: May 6, 2005 Section No. Revision Summary 2.5.16.3...Renumbers the subsections. 2.5.16.3(3)(vi) Replaces the terms Market Monitoring Unit and Independent Market Advisor with Internal Market Monitoring Unit and Independent Market Monitoring Unit. Revision: 12 - Approval Date: May 27, 2005 Section No. Revision Summary The following revision is contingent upon FERC acceptance of corresponding revisions to Market Rule 1 to be filed by the app. The app will request a waiver of the 60-day notice requirement so that the Market Rule 1 revisions may become effective on June 7, 2005. 6.4.10..Adds new subsection titled app Purchases of New Brunswick Security Energy. Revision: 13 - Approval Date: September 9, 2005 Section No. Revision Summary 1.1, 2.5.2 & 3.1...Replace references to OP-20 with references to Appendix H to Market Rule 1. 2.5.8(2), 2.5.9.3(b), 2.5.16.3(4), 5.1, 6.3.2, 6.3.3 & 6.36 Replace references to Section 5 of app Manual M-28 with references to Appendix F to Market Rule 1. Revision: 14 - Approval Date: March 11, 2005 Section No. Revision Summary 1.2.2Adds a reference to Regulation. 1.2.3Adds a new subsection title. 1.2.3(5)...Revises the subsection to provide for hourly posting of preliminary Real-Time Regulation Clearing Prices. 1.2.3(14)&(15) Adds language providing for the posting of preliminary and Real-Time LMPs and RCPs. 2.3...Revises the subsection to allow Resources selected in the Day-Ahead Market to participate in the Re-Offer Period. 2.5.1Revises the subsection to allow Resources selected in the Day-Ahead Market to participate in the Re-Offer Period. 2.5.3(8)...Revises the subsection to allow Resources selected in the Day-Ahead Market to participate in the Re-Offer Period. 2.5.5(7)...Adds the final RCP to the data to be posted. 2.5.6Deletes Mechanical from the subsection title. 2.5.9.2(c) Revises the section to make Real-Time Dispatchable External Transactions eligible to set the Dispatch Rate. 2.5.10..Adds RCP to verification procedure and to title of subsection. 3.1...Completely revises the subsection to describe the new Regulation Market. 3.2.1(2)...Revises the criteria for units participating in the Regulation Market. 3.2.1(3)...Revises the information requirements and redefines Regulation Capability. Also revises the description of the manner in which the software treats Regulation High and Low Limits when they are not the most restrictive limits submitted. 3.2.1(4)(8).These subsections are deleted and replaced with new subsections (4) through (10). 3.2.1(4)...Adds a new subsection describing Minimum Regulation Range. 3.2.1(5)...Adds a new subsection on changing the units Regulation status from available to unavailable. 3.2.1(6)...Adds a new subsection (revised former Section 3.2.1(9)) to describe the treatment of Limited Energy Generators. 3.2.1(7)...Adds a new subsection describing Self-Scheduling for Regulation. 3.2.1(8)...Adds a new subsection setting forth limitations on the submission of Self-Schedule requests. 3.2.1(9)...Adds a new subsection describing the treatment of Opportunity Cost in Self-Scheduled hours. 3.2.1(10).Adds a new subsection describing unit eligibility for Regulation assignment. 3.2.2Revises the subsection to describe the method for setting Regulation Requirements. 3.2.4Deletes the words necessary data. Revises language describing the use of default offer values when no offer is submitted. 3.2.5Adds this new subsection to describe the process of assigning Regulation. 3.2.6Re-writes the subsection to describe the new Regulation Clearing Price calculation. 3.2.7Revises the subsection to describe the new Regulation assignment process. 3.2.8Adds language to provide for Regulation Service Credits and Time-On-Regulation Credits. 3.2.9Revises subsection to provide for monitoring of Automatic Response Rates. 3.2.10..Revises the subsection to use new terminology, delete subsection (2) and re-define the qualifying measurement interval. 3.2.11..Revises the performance calculation to reflect new Regulation Market. 3.2.12..Revises list of existing performance records and adds several items for monitoring of ARR. 3.2.14..Revises subsection to use Regulation Capability Compliance Rating, change rounding to nearest 0.1 MW and add a paragraph dealing with ARR. 5.2.3Eliminates the limitation on Resources that cleared Day-Ahead Market submitting offers in the Re-Offer Period. 5.2.5Revises and re-titles subsection to describe Regulation Assignment and Clearing software. 6.2...Replaces app Regulation Requirement with Regulation Requirement here and throughout the document. 6.2.1(3)...Deletes subsection providing for the notification of Regulation Requirement by 16:00. 6.2.1(4)...Replaces clearing price at 22:00 with hourly clearing of the Regulation Market. 6.2.3Deletes the reference to a 22:00 posting of the Regulation Clearing Price. 6.3...Eliminates the limitation on Resources that cleared in the Day-Ahead Market submitting offers in the Re-Offer Period. 6.3.1Adds references to OP-8 and OP-19. 6.3.4Eliminates the limitation on Resources that cleared in the Day-Ahead Market submitting offers in the Re-Offer Period. 6.3.6Replaces pool-scheduled with Pool-Scheduled. Revision: 15 - Approval Date: December 2, 2005 Section No. Revision Summary The following revisions are part of the Winter 2005/2006 Action Plan and will expire (along with their associated Market Rule 1 provisions) on March 31, 2006. 2.5.1Adds references to Start-Up and No-Load Fees in the timeline to reflect daily submission of these values. 2.5.3(12). Replaces the two eligibility periods twice a month to change Start-Up and No-Load Fees to once per day by noon of the day prior to the Operating Day for which the Start-Up and/or No-Load Fee is to be effective. 6.3...Inserts (excluding Start-Up and No-Load Fees). 6.3.4Inserts (excluding Start-Up and No-Load Fees). The following revisions are conforming changes to reflect Appendix H to Market Rule 1 and will expire with that Market Rule 1 provision on April 15, 2006. Table 1.1.Replaces reference to OP20 with a reference to OP21. 1.1...Adds Except as otherwise provided in Appendix H to Market Rule 1, before the statement describing when the Re-Offer Period begins and ends. 1.1...Adds the revised times for close of the Day-Ahead Energy Market, posting of DAM schedules and the close of the Re-Offer Period. Exhibit 1.1A... Revises the timeline to conform to Appendix H to Market Rule 1. 1.2.3(2)... Deletes at 16:00. 2.3...Deletes at 18:00 in the first paragraph and from 16:00 to 18:00 in the second paragraph. 2.5.1Adds Cold Weather Events to the list of items that may result in changes to the Supply Offer timeline. 2.5.3(25). Revises section to reflect Appendix H to Market Rule 1 process related to Supply Offer caps for internal Resources. Exhibit 3.1.A.. Revises Exhibit 3.1.A to reflect revised Supply Offer deadlines, Re-Offer Period, etc. as detailed in Appendix H to Market Rule 1. 3.2.1(3)... Deletes reference to 18:00 Day-Ahead. 5.1(1).. Deletes prior to 12:00. 5.2.3Revises last paragraph to reflect potential for changed deadlines pursuant to Appendix H to Market Rule 1. 6.2...Adds language to the last sentence indicating the timeline could be adjusted pursuant to Appendix H to Market Rule 1 or for technical reasons. 6.2.1(3)... Deletes a reference to 18:00. 6.3.7Replaces 12:00 noon of the day before with the applicable deadline on the day before. 6.4.8Adds a reference to the Appendix H to Market Rule 1 process. 8.1...Adds under normal conditions to the last sentence. Revision: 16 - Approval Date: October 14, 2005 Section No. Revision Summary 1.2.1, 1.2.1(1), 1.2.3.(3), 5.1(2), 6.1 & 6.3.2. Replaces the terms Daily RMR Resource and RMR Resource with Local Second Contingency Protection Resource. 2.5.3(7)(b), 2.5.3(9), 2.5.9.2(2)(b), 2.5.11(3), 2.5.12(3), 2.5.13(2)(d), (e) & (f), 2.5.14(3), 3.2.7(5), 6.3.1, 6.3.3 & 6.3.5...Replaces the term Operating Reserve with NCPC. 6.3.2... Replaces the term RMR Agreement with Reliability Agreement. Revision: 17 - Approval Date: December 2, 2005 Section No. Revision Summary The following Winter 2005/2006 Action Plan revisions (see Revision 15) have expired (along with their associated Market Rule 1 provisions) on March 31, 2006 and the previous Manual language has been reinstated. 2.5.1Adds references to Start-Up and No-Load Fees in the timeline to reflect daily submission of these values. 2.5.3(12). Replaces the two eligibility periods twice a month to change Start-Up and No-Load Fees to once per day by noon of the day prior to the Operating Day for which the Start-Up and/or No-Load Fee is to be effective. 6.3...Inserts (excluding Start-Up and No-Load Fees). 6.3.4Inserts (excluding Start-Up and No-Load Fees). Revision: 18 - Approval Date: April 7, 2006 Section No. Revision Summary 5.2.2(2)... Replace the term holidays with NERC Holidays and non-NERC Holidays for which the load forecast for the New England Control Area is likely to deviate from the load forecast that would otherwise be expected on a non-holiday. Revision: 19 - Approval Date: December 2, 2005 Section No. Revision Summary The following conforming changes to reflect Appendix H to Market Rule 1 have expired (along with Appendix H to Market Rule 1) on April 15, 2006 and the previous Manual language has been reinstated. (see Revision 9) 1.1...Clarifies that the timeline for scheduling activities in Exhibit 1.1 applies under normal conditions and adds Exhibit 1.1.A to describe the scheduling timeline when a Cold Weather Event is declared pursuant to OP-20. 1.2.3(5)...Replaces 12:00 with the close of the Day-Ahead Energy Market bid/offer period. 2.3...Replaces noon with the close of the Day-Ahead Energy Market bid/offer period. 2.5.1Divides the last sentence of the paragraph into two sentences for clarity. 2.5.7(2)...Replaces 12:00 deadline with the close of the Day-Ahead Energy Market bid/offer period. 3.1...Adds under normal conditions to the description of the Regulation Market Timeline. Adds a new Exhibit 3.1.A to illustrate the Regulation Market Timeline when a Cold Weather Event is declared pursuant to OP-20. 3.2.4Replaces 12:00 with the close of the Day-Ahead Energy Market bid/offer period. 6.4.1(2)&(3)...Replaces 12:00 with the close of the Day-Ahead Energy Market bid/offer period. 6.4.7Replaces 12:00 with the close of the Day-Ahead Energy Market bid/offer period. (see Revision 15) Table 1.1.Replaces reference to OP20 with a reference to OP21. 1.1...Adds Except as otherwise provided in Appendix H to Market Rule 1, before the statement describing when the Re-Offer Period begins and ends. 1.1...Adds the revised times for close of the Day-Ahead Energy Market, posting of DAM schedules and the close of the Re-Offer Period. Exhibit 1.1A... Revises the timeline to conform to Appendix H to Market Rule 1. 1.2.3(2)... Deletes at 16:00. 2.3...Deletes at 18:00 in the first paragraph and from 16:00 to 18:00 in the second paragraph. 2.5.1Adds Cold Weather Events to the list of items that may result in changes to the Supply Offer timeline. 2.5.3(25). Revises section to reflect Appendix H to Market Rule 1 process related to Supply Offer caps for internal Resources. Exhibit 3.1.A.. Revises Exhibit 3.1.A to reflect revised Supply Offer deadlines, Re-Offer Period, etc. as detailed in Appendix H to Market Rule 1. 3.2.1(3)... Deletes reference to 18:00 Day-Ahead. 5.1(1).. Deletes prior to 12:00. 5.2.3Revises last paragraph to reflect potential for changed deadlines pursuant to Appendix H to Market Rule 1. 6.2...Adds language to the last sentence indicating the timeline could be adjusted pursuant to Appendix H to Market Rule 1 or for technical reasons. 6.2.1(3)... Deletes a reference to 18:00. 6.3.7Replaces 12:00 noon of the day before with the applicable deadline on the day before. 6.4.8Adds a reference to the Appendix H to Market Rule 1 process. 8.1...Adds under normal conditions to the last sentence. Revision: 20 - Approval Date: August 11, 2006 Section No. Revision Summary 8.1...Adds language to the end of this section requiring LEG units to notify the app at least 30 minutes prior to a change in LEG status. Revision: 21 - Approval Date: June 2, 2006 Section No. Revision Summary Entire Manual revised to reflect ASM Phase II subjects which include the Locational Forward Reserve Market, Real-Time Reserve Clearing Prices, and Asset Related Demands. Revision: 22 - Approval Date: November 3, 2006 Section No. Revision Summary These FCM Transition Period revisions shall become effective December 1, 2006 and shall be replaced by provisions implementing the Forward Capacity Market on or about June 10, 2010 as provided in the FERC approved Settlement Agreement in Docket No. ER03-563. 1.1...Revises the third paragraph to add references to Non-Dispatchable QFs, Other Demand Resources and Settlement Only Generators. Revises section reference to Market Rule 1. 1.3.1(3)... Adds (External sales are treated as Day-Ahead or Real-Time Load Obligations at the applicable External Node.). 1.3.2(2)... Adds (External purchases are treated as Day-Ahead or Real-Time Generation Obligations at the applicable External Node.). 1.3.2(6)... Deletes a Section reference to Market Rule 1. 2.2...Corrects a Section reference in the last line of the third paragraph. 2.5.3(3)& 2.5.5(8)... Corrects Section references to Market Rule 1. Revision: 23 - Approval Date: May 5, 2006 and August 11, 2006 Section No. Revision Summary This set of revisions was approved on May 5, 2006: 2.5.1... Adds references to Start-Up and No-Load Fees in the timeline to reflect daily submission of these values. 2.5.3(12). Replaces the two eligibility periods twice a month to change Start-Up and No-Load Fees to once per day by noon of the day prior to the Operating Day for which the Start-Up Fee and/or No-Load Fee is to be effective. 2.5.9.2(3)(b)... The word postured is replaced by Postured to reflect the newly defined term added to Market Rule 1 and app Manual M-35. 5.1...The word postured is replaced by Postured to reflect the newly defined term added to Market Rule 1 and app Manual M-35. 6.3 & 6.3.4..Inserts (excluding Start-Up and No-Load Fees). This set of revisions was approved on August 11, 2006 1.1...Adds a reference to the new Exhibit 1.3 which describes the scheduling timeline when a Cold Weather Event is declared pursuant to Market Rule 1. 1.1.1....Adds a new Exhibit 1.3 to describe the scheduling timeline when a Cold Weather Event is declared pursuant to Appendix H to Market Rule 1. 2.5.1Revises the second sentence to add Cold Weather Events as an event which could cause the listed times to be adjusted. 3.1...Adds a new Exhibit 3.1.A to illustrate the Regulation Market Timeline when a Cold Weather Event is declared pursuant to Appendix H to Market Rule 1. 5.2.3Adds (see Appendix H to Market Rule 1 for deadlines during Cold Weather Events) to the first sentence of the fourth paragraph. Revision: 24 - Approval Date: November 3, 2006 Section No. Revision Summary 3.2.5(1)(d).. Deletes the previous subsection (d) language. 3.2.5(1)(d)...Adds to the new subsection (d) the phrase 0.17 multiplied by to the third sentence to now read It is calculated as 0.17 multiplied by the greater of:. 3.2.5(2)... Revises the section reference 3.2.5(1)(c,d,e,f) to now read 3.2.5(1)(c,d,e). Revision: 25 - Approval Date: October 12, 2007 Section No. Revision Summary List of Figures and Tables.. Adds app Business Procedures to the Table 1.1 title. Introduction Adds app Business Procedures to this section. Table 1.1 Adds app Business Procedures to the title and adds Ancillary Service Schedule No. 2 Business Procedure to the Transmission column. Table 2.2 Revises the table by deleting the 1385 Line as part of the Roseton External Node definition and adding a new External Node (.I.NRTHPORT1385) for the 1385 Line (FERC acceptance of corresponding changes to Appendix F to Market Rule 1 was issued by FERC on June 19, 2007 in Docket No. ER07-767-000). Deletes the footnotes (a), (b), (c) and (d) in the table. Revision: 26 - Approval Date: October 12, 2007 Section No. Revision Summary Table 2.2 Revises the table by replacing external node .I.KESWICK 345 1 with .I.SALBRYNB345 1 and adding Lepreau Orrington (390 Line) as an associated transmission facility. Revises the table by deleting HQ - Comerford 451+452 Lines (Phase 1) as an associated facility for the .I.HQ_P1_P2345 5 external node. Revision: 27 - Approval Date: December 7, 2007 Section No. Revision Summary 2.6...Replaces the terms Claim 10 and Claim 30 with CLAIM10 and CLAIM30. 2.6.1....Deletes the phrase such authority as granted in the second paragraph, deletes the third paragraph and deletes the third and fourth sentences in the fourth paragraph. Replaces the term Dispatch with dispatch in the last paragraph. 2.6.2....Revises the title to state 2.6.2 Designated Entity/Lead Market Participant Responsibilities. 2.6.2(3)... Replaces Designated Entity with Lead Market Participant in the first sentence. 2.6.3....Deletes the opening paragraph which duplicated the language contained in Section III.1.11.3(c) of Market Rule 1. 2.6.3(1)... Revises this subsection to describe only the apps performance audit and testing process of CLAIM10 and CLAIM30 capability. 2.6.3(2)... Revises this subsection to describe the apps performance audits of parameters other than CLAIM10 and CLAIM30 capability. 2.6.3(2)(g).. Adds a new subsection detailing the ability of the Designated Entity to request an audit of a Resource to demonstrate that a deficiency identified in an audit has been corrected. 2.6.4, 2.6.5, 2.6.6 & 2.6.7...Deletes these sections in their entirety. Revision: 28 - Approval Date: May 9, 2008 Section No. Revision Summary 2.5.2(3), (7) & (14). Revises the sections to remove the capability of Fixed and Dispatchable External Transactions to have different Source and Sink Locations in the Day-Ahead Energy Market. 2.5.3(19), (21) & (23). Revises the sections to remove the capability of Fixed and Dispatchable External Transactions to have different Source and Sink Locations in the Day-Ahead Energy Market. Table 2.3 Revises the table to remove the capability of Fixed and Dispatchable External Transactions to have different Source and Sink Locations in the Day-Ahead Energy Market. 6.5.4.1(2) Deletes (s), and internal Node, if required. Revision: 29 - Approval Date: June 6, 2008 Section No. Revision Summary Entire Manual revised to reflect Market Rule 1 and Transmission, Markets and Services Tariff provisions filed with the FERC (i.e., provisions making External Transactions comparable to internal generation pursuant to FCM Settlement Agreement). Revision: 30 - Approval Date: June 23, 2008 Section No. Revision Summary 2.3...Revises the third paragraph to clarify a scheduling and delivery practice for priced External Transactions as it may relate to Imports supporting a Capacity Supply Obligation. 2.5.13.1...Deletes Abnormal Conditions Alert in the first and third paragraphs. Revision: 31 - Approval Date: August 1, 2008 Section No. Revision Summary 1.1...Revises this subsection to reflect the prospect of the app being able to schedule External Transactions more than once an hour. 1.1(3).. Revises this subsection to reflect the apps performance of hourly scheduling to cover the entirety of each hour throughout the Operating Day. 2.5.7(5)... Deletes hourly in the phrase hourly transfer limit in the third sentence. Table 2.3 Revises the table by deleting Internal Location not applicable in Real-Time in the Self-Scheduled/priced Real-Time column. 2.5.9.2(1) Revises this subsection to reflect the prospect of the app being able to schedule External Transactions more than once an hour. 2.5.13.1.. Revises the second paragraph by adding the phrase scheduling interval of an and replacing the term next-hour with upcoming. 2.5.13.2.. Revises the second paragraph by replacing upcoming with the next scheduling interval within an, replacing next-hour with upcoming, and replacing in-hour with within a scheduling interval. 6.5.1(1)... Revises the footnote to state that any scheduling interval based on a thirty minute period will be begin at the top of the hour or thirty minutes after the top of the hour. 6.5.3... Revises the section by deleting hourly in the phrase hourly ramp constraints and replacing hour with scheduling interval. 6.5.4.1(2) Revises the phrase External Node to External Node(s), and internal Node, if required. 6.5.7... Revises the section by replacing Next Hour with for Next Scheduling Interval in the title and within the paragraph. Replaces hour with interval in the second sentence. Revision: 32 - Approval Date: June 6, 2008 and June 22, 2009 Section No. Revision Summary This set of revisions was approved on June 6, 2008 6.5.4.2(7-10)... Revises the subsections to address the submittal timing of External Transaction information for the Real-Time Energy Market. 6.5.5....Revises the app review process for specific priced Real-Time External Transactions that have been submitted in support of an ICAP Import Contract which have a Pending Action status. 6.5.7....Revises the Real-Time Energy Market Next Hour Check-Out process for Real-Time priced External Transactions. This set of revisions was approved on June 22, 2009 Sections 1, 2 and 6... Revises these three sections to reflect competitive offer requirements for ICAP Import Contracts. Revision: 33 - Approval Date: May 7, 2010 Section No. Revision Summary Entire Manual revised to reflect the Forward Capacity Market as contained in Section III.13 of Market Rule 1. Revision: 34 - Approval Date: November 18, 2010 Section No. Revision Summary Throughout the manual... Replaces business days with the defined term Business Days, utilizes military time (without colons), utilizes manual rather than Manual when not naming the manual (e.g., Manual M-11), and, with several exceptions, expressing numbers 1-9 by utilizing the words one through nine and expressing all higher numbers as numerals. Introduction Incorporates standardized description of the content and purpose of app Manuals and deleted Section listing. Opening Introduction for each Section... Deletes the opening introduction for each Section. 2.5.3(19). Revises the subsection to refer to the Market Rule 1 offer requirements for External Transactions associated with Import Capacity Resources. 6.5...Revises the section to reference the competitive offer requirement in Section III.13.6.1.2.1 of Market Rule 1 for priced External Transactions. 6.5.2....Revises the section to delete obsolete reference to app Manual M-20, and revises a subsection that might imply rejection of External Transactions where the aggregate amount of such transactions is less than an associated Capacity Import Contracts Capacity Supply Obligation. 6.5.3Revises the section to eliminate reference to warnings (ramp constraint status is routinely posted, there is no explicit warning) and to clarify the section. 6.5.6Revises the section to refer to Market Rule 1 and OATT provisions that provide detailed scheduling information for various types of External Transactions and to refer to the adjustments and penalties that may apply to Import Capacity Resources. Revision: 35 - Approval Date: October 15, 2010 Section No. Revision Summary Table 2.2 Replaces Keswick Orrington (396 Line) with Keene Road Keswick (3001). Revision: 36 - Approval Date: January 7, 2011 Section No. Revision Summary 1.1.. Adds the phrase , or are not otherwise required to submit a Supply Offer under the app Tariff, to the second sentence within the fourth paragraph. 1.3.2(5)(a).. Adds the phrase , or are not otherwise required to submit a Supply Offer under the app Tariff, to the first sentence. 1.3.2(5)(b).. Creates a new subsection (b) from the second sentence previously contained in Section 1.3.2(5)(a). 2.2...Adds the phrase , or are not otherwise required to submit a Supply Offer under the app Tariff, to the fourth sentence within the fourth paragraph. 2.5.3(3)... Adds the phrase , or are not otherwise required to submit a Supply Offer under the app Tariff, to the second sentence. 2.5.3(14)(a) Adds the phrase , or are not otherwise required to submit a Supply Offer under the app Tariff, to the first sentence. Revision: 37 - Approval Date: December 10, 2010 Section No. Revision Summary 6.3.2... Deletes the third and fourth sentences in the second paragraph which conforms this Manual to the Appendix A to Market Rule 1 sunset of provision Section III.A.6 Reliability Agreements. Revision: 38 - Approval Date: April 1, 2011 Section No. Revision Summary 2.5.2....Adds citation to access details on requesting the demand response enrollment information contained in app Manual M-RPA. Revision: 39 - Approval Date: January 20, 2012 Section No. Revision Summary 2.5.6(3)... Deletes the sentence Hourly Maximum Consumption Limit must be greater than or equal to five MW. Revision: 40 - Approval Date: May 6, 2011 Section No. Revision Summary 2.5.1, 2.5.3(7)&(11), 6.3 & 6.3.4. Removes language that prohibited updates to the Start-Up and No-Load parameters of the Supply Offer during the Re-Offer Period. 2.5.2(2)... Clarifies that only one hourly fixed Demand Bid quantity can be submitted for the next Operating Day. 2.5.2(9)... Clarifies that up to ten price sensitive Demand Bid blocks can be submitted. 2.5.2(16). Clarifies that up to fifty Decrement Bid blocks per hour can be submitted. 2.5.2(18). Adds the sentence Market Participants may submit up to ten Demand Bid blocks per day for each Dispatchable Asset Related Demand Bids the Day-Ahead Energy Market. 2.5.3(10). Clarifies that a Supply Offer for a Generator may consist of up to ten incremental Energy offer blocks. 2.5.3(17). Clarifies that up to fifty Increment Offer blocks per hour can be submitted. Revision: 41 - Approval Date: June 1, 2012 Section No. Revision Summary 1.3...Revises the section to add Demand Reduction Offers. 1.3.4.2.Adds Day-Ahead Demand Reduction Offer of Real-Time Demand Response Asset. Changes OP-4 dispatch trigger to declaration from forecast OP-4. Deletes third paragraph and adds a new paragraph to describe capacity and energy dispatch of Real-Time Demand Response Resources, Real-Time Emergency Generation Resources (OP-4 dispatch) and energy dispatch under Appendix III.E of Real-Time Demand Response Assets. 2.3.. Revises dispatch language to eliminate advance notice and deletes the word increase. 5.1(5).. Adds language on OP-4 dispatch of Real-Time Demand Response Resources. Revision: 42 - Approval Date: October 3, 2012 Section No. Revision Summary 6.5.7....Deletes the phrase that were submitted by 1200 on the day before the Operating Day within the Real-Time Energy Market Day Before Checkout subsection. Revision: 43 - Approval Date: January 4, 2013 Section No. Revision Summary 3.2.4(3)... Deletes this subsection in its entirety. 5.2.3(2)... Deletes the phrase for Regulation within this subsection. 6.2.2... Deletes the third sentence Market Participants use the MUI to submit Internal Bilateral Transactions for Regulation that must be submitted prior to the Real-Time Internal Bilateral Transaction Trading Deadline. in this section. Exhibit 6.3.. Deletes the Internal Bilateral Trans. phrase which was contained in the Other app Systems flow chart box. Revision: 44 - Approval Date: May 3, 2013 Section No. Revision Summary 1.1, 1.2.1(2), 1.2.3, 1.2.3(2), (4), (5) and (7), 1.3.4.1(1), 1.3.4.2, 2.3, Table 2.2, 2.5.1, 2.5.3(7), (11), (14), (16)(e), (27), (27)(a) and (b), 2.5.5(4), 2.5.6(4) bullets 3 and 4, 2.5.10(1)(a), 2.5.13.1, 2.5.13.2, 3.1, 3.2.1(3), 3.2.2(2), 3.2.3(1)(b), 3.2.4(1), 5.1 bullet 4, 5.2 bullet 7, 5.2.2(1), 5.2.3, 5.2.5, 6.2, 6.2.1(3), 6.2.2, 6.2.3, 6.3.8, 6.5.1(2), (3) and (4), 6.5.9, 8.1. These Sections were revised to reflect the earlier clearing of the Day-Ahead Energy Market and earlier completion of the initial Reserve Adequacy Analysis process. Exhibits 1.1, 1.2, 1.3, 3.1, 3.1.A, 6.2, 6.3, 8.1... These Exhibits were deleted to reflect the earlier clearing of the Day-Ahead Energy Market and earlier completion of the initial Reserve Adequacy Analysis process. Revision: 45 - Approval Date: June 7, 2013 Section No. Revision Summary 2.5.3(12), 2.5.5(6), 2.5.6(1)&(3), & 2.5.9.3 Replaces Claim 10 and Claim 30 terminology with the defined terms CLAIM10 and CLAIM30. Revision: 46 - Approval Date: June 27, 2013 Section No. Revision Summary 2.5.9.2(2)(b)... Updates cross reference to point to app Manual for the Regulation Market (M-REG). 3. Deletes this section and relocates the information to app Manual for the Regulation Market (M-REG). 5.2.6... Updates cross reference to point to app Manual for the Regulation Market (M-REG). 6.2.1, 6.2.2, 6.2.3 and Exhibit 6.2.. Deletes these subsections and exhibit, and relocates this information to app Manual for the Regulation Market (M-REG). Revision: 47 - Approval Date: August 2, 2013 Section No. Revision Summary 2.4(4).. Replaces reference to Table 2.2 with a reference to Section III.F.3.2.16 of Market Rule 1. Table 2.2.Deletes Table 2.2. Revision: 48 - Approval Date: November 7, 2014 Section No. Revision Summary Entire Manual revised to reflect Market Rule 1 language implementing the energy market offer flexibility rules and Net Commitment Period Compensation payment rules; clean-up changes and updates; and the current structure and purpose of app-NE Manuals. Revision: 49 - Approval Date: March 6, 2015 Section No. Revision Summary 2.2.8Deletes this section and reserves the section number. 2.2.9Deletes this section and reserves the section number.  On and after June 1, 2017, Demand Response Resources will become Resources but will be obligated to submit Demand Reduction Offers not Supply Offers.  app will implement schedules for less than full-hour intervals when all Control Areas and dispatching authorities on the scheduling path have agreed to such intervals, provided apps staff has scheduling, dispatch and settlement software and/or business practices in place to allow shorter schedules to be developed, implemented and settled. Any such scheduling interval based on 15 minutes or multiples of 15 minutes will begin at the top of the hour, or at 15, or 30, or 45 minutes after the top of the hour. Any such scheduling interval based on 30 minutes will begin at the top of the hour or 30 minutes after the top of the hour.     Market Operations Manual Table of Contents app.  PAGE ii Revision __, Effective Date: ________ Market Operations Manual Table of Contents app.  PAGE iii Revision 49, Effective Date: May 27, 2015 app.  PAGE i Revision 49, Effective Date: May 27, 2015 Market Operations Manual Introduction app. INT- PAGE 2 Revision 33, Effective Date: June 1, 2010 app. INT- PAGE 1 Revision 49, Effective Date: May 27, 2015 Market Operations Manual Section 1: Overview of Energy Market Operations app. 1- PAGE 7 Revision 49, Effective Date: May 27, 2015 app. 1-1 Revision 49, Effective Date: May 27, 2015 Market Operations Manual Section 2: Energy Market app. 2- PAGE 15 Revision 49, Effective Date: May 27, 2015 app. 2- PAGE 1 Revision 49, Effective Date: May 27, 2015 Market Operations Manual Section 3: Scheduling app. 3 PAGE 8 Revision 49, Effective Date: May 27, 2015 app. 3- PAGE 1 Revision 49, Effective Date: May 27, 2015 Market Operations Manual Revision History app. REV- PAGE 17 Revision 49, Effective Date: May 27, 2015 app. REV- PAGE 1 Revision 49, Effective Date: May 27, 2015 GHIJK[^_abfg  _ c |    $ ' @ A ] ` ~zh?hhx`hQhz$h i}hKJhjF6] hKJ6 hKJ6]hKJ hjF6] h 6] hjFCJhq+hYYcHhEghYYcHhChYYcHh5cghYYcHhkhYYcHhjFhYYcHhjF./;<=>Khijklx- c ( a ,  3 \ , M @*^*gdKJ@gd ' ( + ,    / 2 3 5 6 < X [ ^ _ t   ( + , 4 H I L U e f i r 3STVW˻˿𿷿hdrh='hh^+heTh hx6] hjF6]hhKJhjF6] hKJ6hjFhKJhz$h&5HM j To*Vm8V H@*^*gdeT@gd@gd@*^*gdKJWjnqrt %)*5UV^_mnopqhey hjF6] h 6] hey6] hEg6]hh #?#e$mZmGm7mh(.wB*CJOJQJaJph%h(.whB*CJOJQJaJph%h(.whfB*CJOJQJaJph%h(.whdB*CJOJQJaJphh,hE(CJOJQJ]aJhCJOJQJ\]aJ#HhCJOJQJ\]aJhijCJOJQJ\]aJ"h,hE(CJOJQJ\]aJ/h,hE(hCJOJQJ\]aJcH)hhCJOJQJ\]aJcHe$%%%'''-'''(((())8)9){)))8*9*}*****+7+8+9+V,Z,[,`,d,,,,,,,,,,,ǹǹǧ~w~ hh2| hhjF hh hhwshi$hqh2|hhwsh@+ hmh&. hhIu hmhIu hmh(.w hmh@+ hmh hmhjF^JhXh1FM hjF^Jhs)hlk9h(.whwAhjF.V,,[--A.v.//011;334455^6T7$>^`>a$gde$>^`>a$gd(.w$|Bxx^|`Ba$gd;) & F>^`>gd(.w$a$gdb$a$) & F>^`>gdws,,- ----C-O-Y-Z-[-_-`---------?.A.v.../// //b////////0000 00/030<0=0>0E0J0u0ؽؽؽhp h3mhp h3mhbjhb0JtUhGpNhe Bhbhhe Bhh(.whb hjF^Jhq hjFhh2|hPhhwshjF hhjF hh) hhX hhq5u0x0011111I1^1111111112 2O2P2Q222223"353:3;3?3@3f33333333U4»Ψ{h;hU|CJOJQJaJh;hGpNCJOJQJaJh;hbCJOJQJaJh;hwsCJOJQJaJh hqhbh(.whGpNhGA9hh!qh!qhh!qhhwshe BhQhb h3mhb hrGhp*U4444444444444445354585Q5x5555566?6]6^6c6%7&7S7T7777777%8G8H8i8¾ںںڶޯ~w h,hjF heaJheh aJhehjFaJheh,aJh#hjFhehd z hAhd zh h25hyKhGpNhd zhlhhd zhbhhlhbhwsh;hbCJOJQJaJh;hbCJOJQJaJ,T77H88!9':;X;n<o<p<<<,>U> $^a$gd(.w$$d N a$gdEg&$$d%d&d'dNOPQa$ ! & F`P^``P$a$#) & F>^`>gdwsgds $^a$gdegdei888 9!9$9&9)9=9C9D9T9b9o99999999/::::::::;X;;;;;,<M<l<m<p<<<<<======x=y==׼ϸ߲DžӅh#|UhEg6CJ]^JhEgKH\^JhjFKH\^JhyKh4}hjF hjF^Jh"T h3mh"Th\h(.whRhhh2ohwshhhshd]^J hd]^J h,hjF h,h#.4====== > >>>>*>+>,>;><>T>U>>>E?F???@ @f@g@@@@@@@AABBCC CCXCYCDý̱whjCJOJQJaJ"hy"hA5>*CJOJQJaJhpCJOJQJaJhy"hA5CJOJQJaJhACJOJQJaJ h(.waJhphYEaJhphy"aJh3ehvlhth6h#|U h#|Uh#|Uh(.whjFh\Kh,,U>@DDD D^DEYI J+JPJJLNOPQR?SS *$^a$gdR$a$#$a$O$xx^a$gd(.w$a$gdA $^a$gdA $xxa$gdp $xxa$gd(.wDD D^DDDDDDEEEEAFBFFFFFFFFGGGqGrGGGHHHHYI J J J-J.JPJZJuJJJJJJ㚦㚦㔎~zvzvrvhmh;M*hjFhhX5>* h^ ^J hjF^J hAaJhH.CJOJQJaJhpCJOJQJaJhy"hACJOJQJaJhy"hA5CJOJQJaJ"hA56CJOJQJ\]aJhACJOJQJaJjhACJOJQJUaJ,JJKK'K7K8KCKIKJKUKtKuKvKKKKKKKKKK L LLLLLLMMNJNMNyNNNNNNOOhOOOOOP Pھڷ} hhq^ h^Chq^ hhe B hh hhjFh% hVZk5>*h?)h}Yhpm hh?) hh hhyg hhi hh" hh!WhRh!Whbfh3ehX hX5>*hjF1 P PP/P:PGPPPPPPPPPQQQQQQQQQQQQRR R>R?RJRORcR~RRRR>S?SSSSSSSSSSS7T8Tޑލޣޣޑ hhhAuh"vhk hjF5>* hjhq^hkYhhU hb,h hb,hq^hRh,hh`p#5>*h!W hYYh!Wh hjFh3ehe BhUruhq^ hYYhq^ h^Chq^38T9TzTTTTTUMUlUmUnUpUqUrUUUUUUUUV:V?VFVRVuVVVVVVVVVVVVVWWHXIXXXXX/Y1Y2Y3YWY[YaYmYYYYYƿƸƴܝ hh; hhExhExhtehvlh\h/V hh hh :j hh/Vh :jhJ$ hhjFhh}YhR h^ ^J hjF^JhjFhK.hAu;STUnUUUWGX/YYZ\ab c(dWeeff( & F%^`%gdClgd( & F nB^n`Bgd9B( & FnB^n`BgdClgdR$a$$a$ *$^a$gdRYYZ Z#ZZZZ[[[([A[k[v[[[[[[[[[[[[[[g\h\\\\\\\\W]X]]]n^p^q^^_ƿƿ𢞗 hhk hhEx hha hh`%hhExhk hh}Y hhBf hh hhUru hh1 hh hh :j hh/V hhjF h/Vh/Vhvlh :jh/VhjF-_ ___` `.`0`<`=`v``````aCaNaaaabbbbbbc c ccc'd(d-dddddVeWe\eeeefԿԈԏԏ}yuh8h}Y h\ThhjF hh;phExhvlhh@Gh HhEx Hh% Hh9B Hhjh. 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