Interchange.puc.texas.gov
OPEN ACCESS
TRANSMISSION SERVICE TARIFF
OF THE
AMERICAN ELECTRIC POWER SYSTEM
Appalachian Power Company
Central Power and Light Company
Columbus Southern Power Company
Indiana Michigan Power Company
Kentucky Power Company
Kingsport Power Company
Ohio Power Company
Public Service Company of Oklahoma
Southwestern Electric Power Company
West Texas Utilities Company
Wheeling Power Company
(Collectively “AEP”)
American Electric Power Service Corporation, as agent for Appalachian Power Company, Central Power and Light Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Kingsport Power Company, Ohio Power Company, Public Service Company of Oklahoma, Southwestern Electric Power Company, West Texas Utilities Company and Wheeling Power Company files this Tariff to comply with the Federal Energy Regulatory Commission's (FERC) Order No. 888, issued in Docket No. RM95-8-000, "Promoting Wholesale Competition through Open Access Non-discriminatory Transmission Service by Public Utilities," FERC Stats. & Regs., Regulations Preambles ¶ 31,036 (1996), reh'g, Order No. 888-A, FERC Stats. & Regs., Regulations Preambles ¶ 31,048 (1997), reh'g, Order No. 888-B, 81 FERC ¶ 61,248 (1997), reh'g, Order No. 888-C, 82 FERC ¶ 61,046 (1998). The transmission and ancillary services offered for sale under this Tariff are the transmission and ancillary services that the FERC has ordered public utilities subject to its jurisdiction to offer to Eligible Customers, as that term is defined in this Tariff. This Tariff also implements certain of the transmission access and service pricing policies of the Public Utilities Commission of Texas generally in accordance with Chapter 25 of that Commission's Substantive Rules. If the PUCT Chapter 25 of the PUCT’s Substantive Rules or Order No. 888 is modified in the future, the terms on which transmission and ancillary services are offered under this Tariff may also be modified pursuant to the provisions of Section 9 of this Tariff.
Public Service Company of Oklahoma and Southwestern Electric Power Company are members of the Southwest Power Pool. The SPP offers certain transmission services acting as their designated agent under the Open Access Transmission Tariff for Service Offered by Southwest Power Pool filed with the Federal Energy Regulatory Commission (SPP Tariff).
OPEN ACCESS TRANSMISSION SERVICE TARIFF
OF THE
AEP OPERATING COMPANIES
TABLE OF CONTENTS
OPEN ACCESS TRANSMISSION SERVICE TARIFF 15
I COMMON SERVICE PROVISIONS 15
1. Definitions 15
1.1 AEP East Zone 15
1.2 AEP West Zone 15
1.3 AEP Operating Companies 15
1.4 Ancillary Services 15
1.5 Annual Transmission Costs 15
1.6 Application 16
1.7 Chapter 25 16
1.8 Commission 16
1.9 Completed Application 16
1.10 Control Area 16
1.11 CPL 17
1.12 Curtailment 17
1.13 Delivering Party 17
1.14 Designated Agent 17
1.15 Direct Assignment Facilities 17
1.16 ECAR 17
1.17 Eligible Customer 17
1.18 ERCOT 18
1.19 ERCOT Ancillary Services 18
1.20 ERCOT Service Date 18
1.201 ERCOT Ancillary Services CustomerProtocols 19
1.212 ERCOT ISO 19
1.22 ERCOT Power Supplier 19
1.23 ERCOT Regional Transmission Service 19
1.24 ERCOT Regional Transmission Service Customer 20
1.25 ERCOT Transmission Network 20
1.26 Facilities Study 20
1.27 Firm Point-to-Point Transmission Service 20
1.28 Good Utility Practice 20
1.29 High-Voltage Direct Current Facilities (or "HVDC Facilties") 21
1.30 HLP 21
1.310 Interconnection Agreement 22
1.321 Interruption 22
1.332 Load Ratio Share 22
1.34 Load Serving Entity
1.353 Load Shedding 22
1.364 Long-Term Firm Point-To-Point Transmission Service 22
1.375 Native Load Customers 23
1.386 NERC 23
1.397 Network Customer 23
1.4038 Network Integration Transmission Service 23
1.4139 Network Load 23
1.420 Network Operating Agreement 24
1.431 Network Operating Committee 24
1.442 Network Resource 24
1.453 Network Upgrades 25
1.464 Non-Firm Point-To-Point Transmission Service 25
1.475 Open Access Same-Time Information System (OASIS) 25
1.486 Part I 25
1.497 Part II 25
1.5048 Part III 26
1.5149 Part IV 26
1.520 Parties 26
1.53 Planned Resource 26
1.54 Planned Service 26
1.551 Point(s) of Delivery 27
1.562 Point(s) of Receipt 27
1.573 Point-To-Point Transmission Service 27
1.584 Power Purchaser 27
1.595 PSO 27
1.6056 PUCT 27
1.57 QSE 27
1.6158 Receiving Party 28
1.6259 Regional Transmission Group (RTG) 27
1.630 Reserved Capacity 28
1.61 Retail Electric Provider (REP) 28
1.642 Service Agreement 28
1.653 Service Commencement Date 28
1.664 Short-Term Firm Point-To-Point Transmission Service 29
1.675 SPP 28
1.686 SWEPCO 29
1.697 System Impact Study 29
1.7068 Third-Party Sale 29
1.7169 Transmission Customer 29
1.720 Transmission Provider 30
1.731 Transmission Provider's Monthly Transmission System Peak 30
1.742 Transmission Service 30
1.753 Transmission System 30
1.764 TXU Electric 31
1.77 Unplanned Resource 31
1.78 Unplanned Service 31
1.795 WTU 31
2 Initial Allocation and Renewal Procedures 31
2.1 Not Applicable 31
2.2 Reservation Priority For Existing Firm Service Customers 31
3 Ancillary Services 32
3.1 System Scheduling, System Control and Dispatch Service 35
3.2 System Reactive Supply and Voltage Control from Generation Sources
Service 35
3.3-A System Regulation and Frequency Response Service 35
3.3-B System Load Following Service 35
3.4 System Energy Imbalance Service 35
3.5 System Operating Reserve - Spinning Reserve Service (ECAR and
SPP) or Responsive Reserve Service (ERCOT) 35
3.6 System Operating Reserve - Supplemental Reserve Service (ECAR and
SPP) or Spinning Reserve Service (ERCOT) 35
3.7 ERCOT Responsive Reserve Service 29
3.8 ERCOT Spinning Reserve Service 29
3.9 ERCOT Static Scheduling Service 29
3.10 ERCOT Dynamic Scheduling Service 29
3.11 ERCOT Load Following Service 29
3.12 ERCOT Load Regulation Service 29
3.13 ERCOT Generation Schedule Imbalance Service 30
3.14 ERCOT Load Schedule Imbalance Service 30
3.15 ERCOT Schedule Backup Service 30
3.16 ERCOT Automatic Backup Service 30
3.17 ERCOT Emergency Energy Service 30
4 Open Access Same-Time Information System (OASIS) 37
5 Upgrades to HVDC Facilities 37
6 Reciprocity 38
7 Billing and Payment 39
7.1 Billing Procedure 39
7.2 Interest on Unpaid Balances 39
7.3 Customer Default 40
8 Accounting for the Transmission Provider's Use of the Tariff 41
8.1 Transmission Revenues 41
8.2 Study Costs and Revenues 41
9 Regulatory Filings 41
10 Force Majeure and Indemnification 42
10.1 Force Majeure 42
10.2 Indemnification 42
11 Creditworthiness 43
12 Dispute Resolution Procedures 45
12.1 Internal Dispute Resolution Procedures 45
12.2 External Arbitration Procedures 46
12.3 Arbitration Decisions 46
12.4 Costs 47
12.5 Arbitration under Part IV 47
12.56 Rights Under The Federal Power Act 47
II POINT-TO-POINT TRANSMISSION SERVICE 48
Preamble 48
13 Nature of Firm Point-To-Point Transmission Service 51
13.1 Term 51
13.2 Reservation Priority 51
13.3 Use of Firm Transmission Service by the Transmission Provider 52
13.4 Service Agreements 52
13.5 Transmission Customer Obligations for Facility Additions or Redispatch
Costs 53
13.6 Curtailment of Firm Transmission Service 54
13.7 Classification of Firm Transmission Service 55
13.8 Scheduling of Firm Point-To-Point Transmission Service 57
13.9 Commonly Owned Facilities 59
14 Nature of Non-Firm Point-To-Point Transmission Service 59
14.1 Term 59
14.2 Reservation Priority 60
14.3 Use of Non-Firm Point-To-Point Transmission Service by the
Transmission Provider 61
14.4 Service Agreements 61
14.5 Classification of Non-Firm Point-To-Point Transmission Service 61
14.6 Scheduling of Non-Firm Point-To-Point Transmission Service 62
14.7 Curtailment or Interruption of Service 64
14.8 Commonly Owned Facilities 66
15 Service Availability 66
15.1 General Conditions 66
15.2 Determination of Available Transmission Capability 67
15.3 Initiating Service in the Absence of an Executed Service Agreement 67
15.4 Obligation to Provide Transmission Service that Requires Expansion or
Modification of the Transmission System 68
15.5 Deferral of Service 68
15.6 Other Taransmission Service Schedules 69
15.7 Real Power Losses 69
16 Transmission Customer Responsibilities 71
16.1 Conditions Required of Transmission Customers 71
16.2 Transmission Customer Responsibility for Third-Party Arrangements 72
17 Procedures for Arranging Firm Point-To-Point Transmission Service 73
17.1 Application 73
17.2 Completed Application 73
17.3 Deposit 75
17.4 Notice of Deficient Application 76
17.5 Response to a Completed Application 77
17.6 Execution of Service Agreement 77
17.7 Extensions for Commencement of Service 78
18 Procedures for Arranging Non-Firm Point-To-Point Transmission Service 79
18.1 Application 79
18.2 Completed Application 79
18.3 Reservation of Non-Firm Point-To-Point Transmission Service 80
18.4 Determination of Available Transmission Capability 81
19 Additional Study Procedures For Firm Point-To-Point Transmission Service
Requests 82
19.1 Notice of Need for System Impact Study 82
19.2 System Impact Study Agreement and Cost Reimbursement 83
19.3 System Impact Study Procedures 84
19.4 Facilities Study Procedures 85
19.5 Facilities Study Modifications 86
19.6 Due Diligence in Completing New Facilities 87
19.7 Partial Interim Service 87
19.8 Expedited Procedures for New Facilities 87
20 Procedures if The Transmission Provider is Unable to Complete New
Transmission Facilities for Firm Point-To-Point Transmission Service 88
20.1 Delays in Construction of New Facilities 88
20.2 Alternatives to the Original Facility Additions 89
20.3 Refund Obligation for Unfinished Facility Additions 90
21 Provisions Relating to Transmission Construction and Services on the Systems of
Other Utilities 90
21.1 Responsibility for Third-Party System Additions 90
21.2 Coordination of Third-Party System Additions 91
22 Changes in Service Specifications 92
22.1 Modifications On a Non-Firm Basis 92
22.2 Modification On a Firm Basis 93
23 Sale or Assignment of Transmission Service 93
23.1 Procedures for Assignment or Transfer of Service 93
23.2 Limitations on Assignment or Transfer of Service 94
23.3 Information on Assignment or Transfer of Service 95
24 Metering and Power Factor Correction at Receipt and Delivery Point(s) 95
24.1 Transmission Customer Obligations 95
24.2 Transmission Provider Access to Metering Data 96
24.3 Power Factor 96
25 Compensation for Transmission Service 96
26 Stranded Cost Recovery 97
27 Compensation for New Facilities and Redispatch Costs 97
III. NETWORK INTEGRATION TRANSMISSION SERVICE 97
Preamble 97
28 Nature of Network Integration Transmission Service 100
28.1 Scope of Service 100
28.2 Transmission Provider Responsibilities 100
28.3 Network Integration Transmission Service 101
28.4 Secondary Service 101
28.5 Real Power Losses 102
28.6 Restrictions on Use of Service 102
29 Initiating Service 103
29.1 Condition Precedent for Receiving Service 103
29.2 Application Procedures 104
29.3 Technical Arrangements to be Completed Prior to Commencement of
Service 109
29.4 Network Customer Facilities 109
29.5 Filing of Service Agreement 109
30 Network Resources 110
30.1 Designation of Network Resources 110
30.2 Designation of New Network Resources 110
30.3 Termination of Network Resources 110
30.4 Operation of Network Resources 111
30.5 Network Customer Redispatch Obligation 111
30.6 Transmission Arrangements for Network Resources Not Physically
Interconnected With The Transmission Provider 111
30.7 Limitation on Designation of Network Resources 112
30.8 Use of Interface Capacity by the Network Customer 112
30.9 Network Customer Owned Transmission Facilities 112
31 Designation of Network Load 113
31.1 Network Load 113
31.2 New Network Loads Connected With the Transmission Provider 113
31.3 Network Load Not Physically Interconnected with the Transmission
Provider 114
31.4 New Interconnection Points 115
31.5 Changes in Service Requests 115
31.6 Annual Load and Resource Information Updates 115
32 Additional Study Procedures For Network Integration Transmission Service
Requests 116
32.1 Notice of Need for System Impact Study 116
32.2 System Impact Study Agreement and Cost Reimbursement 117
32.3 System Impact Study Procedures 118
32.4 Facilities Study Procedures 119
33 Load Shedding and Curtailments 120
33.1 Procedures 120
33.2 Transmission Constraints 121
33.3 Cost Responsibility for Relieving Transmission Constraints 121
33.4 Curtailments of Scheduled Deliveries 122
33.5 Allocation of Curtailments 122
33.6 Load Shedding 122
33.7 System Reliability 123
34 Rates and Charges 124
34.1 Monthly Demand Charge 124
34.2 Determination of Network Customer's Monthly Network Load 124
34.3 Determination of Transmission Provider's Monthly Transmission System
Load 129
34.4 Redispatch Charge 130
34.5 Stranded Cost Recovery 130
35 Operating Arrangements 130
35.1 Operation under The Network Operating Agreement 130
35.2 Network Operating Agreement 131
35.3 Network Operating Committee 132
IV ERCOT REGIONAL TRANSMISSION SERVICE 132
36 ERCOT Regional Transmission Service 133
36.1 Purpose 133
36.2 Nature of Transmission Service 134
37 Availability of Transmission Service 135
37.1 General Conditions 135
37.2 Transmission Service Requirements 135
37.3 Transmission Provider Responsibilities 136
37.4 Transmission Customer Redispatch Obligation 140
37.5 Reactive Power 141
37.6 Priority of Transmission Service Applications 141
37.74 Construction of New Facilities 138
37.8 Resale of Transmission Rights 144
37.9 Scheduling 144
38 Initiating Service 141
38.21 Conditions Precedent for Receiving Service 141
38.32 Application Procedures for Annual Planned ERCOT
Regional Transmission Service 143
38.4 Application Procedures for Other Planned Service 151
38.5 Application for Unplanned ERCOT Regional Transmission
Service 152
38.6 System Impact Study 156
38.73 Facilities Study 154
38.84 Technical Arrangements to be Completed Prior to Commencement of
Service 156
38.95 Transmission Customer Facilities 156
38.106 Transmission Arrangements for Resources Located Outside of the
ERCOT Region 157
38.117 Changes in Service Requests 157
38.128 Annual Load and Resource Information Updates 158
38.139 Termination of Planned Transmission Service 158
38.140 Initiating Service in the Absence of an Executed Service Agreement 159
39 Planned Resources 163
39.1 Designation of Planned Resources 163
39.2 Designation of New Planned Resources 163
4039 Rates and Charges 161
4039.1 Demand Charge for Planned ERCOT Regional Transmission Service 161
40.2 Access Fee 165
40.3 Loss Charges for Planned Service 165
40.4 Charges for Unplanned Service 165
41 Load Shedding and Curtailments 165
41.1 Procedures 165
41.2 Transmission Constraints and Redispatch 166
41.3 Cost Responsibility for Relieving Capacity Constraints 168
39.2 Commercial Terms for Transmission Service 166
401.4 System Reliability 169
412 ERCOT Ancillary Services 170
412.1 Responsibility for ERCOT Ancillary Services 170
412.2 ERCOT Ancillary Services 172
412.3 Initiating ERCOT Ancillary Service 175
412.4 Application Procedures for ERCOT Ancillary Services 175
412.5 Technical Arrangements to be Completed Prior to Commencement of
ERCOT Ancillary Services 178
412.6 Termination of ERCOT Ancillary Services 178
412.7 Notification 179
412.8 Initiating Service in the Absence of an Executed Service Agreement 179
41.9 Qualified Scheduling Entity Service 180
SCHEDULE 1
SYSTEM SCHEDULING, SYSTEM CONTROL AND DISPATCH SERVICE` 182
SCHEDULE 2
SYSTEM REACTIVE SUPPLY AND VOLTAGE CONTROL FROM
GENERATION SOURCES SERVICE 185
SCHEDULE 3-A
SYSTEM REGULATION AND FREQUENCY RESPONSE SERVICE 188
SCHEDULE 3-B
SYSTEM LOAD FOLLOWING SERVICE 192
SCHEDULE 4
SYSTEM ENERGY IMBALANCE SERVICE (ECAR and SPP) 194
SCHEDULE 4-A
RETAIL ENERGY IMBALANCE SERVICE 200
SCHEDULE 5
SYSTEM OPERATING RESERVE -- SPINNING RESERVE SERVICE
(ECAR and SPP) OR RESPONSIVE RESERVE SERVICE (ERCOT) 207
SCHEDULE 6
SYSTEM OPERATING RESERVE -- SUPPLEMENTAL RESERVE SERVICE (ECAR
and SPP) OR SPINNING RESERVE SERVICE (ERCOT) 211
SCHEDULE 7
LONG-TERM FIRM AND SHORT-TERM FIRM POINT-TO-POINT
TRANSMISSION SERVICE 215
SCHEDULE 8
NON-FIRM POINT-TO-POINT TRANSMISSION SERVICE 217
SCHEDULE 9
ERCOT RESPONSIVE RESERVE SERVICEREGULATION SERVICE-UP 220
SCHEDULE 10
ERCOT SPINNING RESERVE SERVICEREGULATION SERVICE-DOWN 222
SCHEDULE 11
ERCOT STATIC SCHEDULING SERVICERESPONSIVE RESERVES SERVICE 224
SCHEDULE 12
ERCOT DYNAMIC SCHEDULING SERVICENON-SPINNING RESERVE SERVICE 226
SCHEDULE 13
ERCOT LOAD FOLLOWING SERVICE 222
SCHEDULE 14
ERCOT LOAD REGULATION SERVICE 225
SCHEDULE 15
ERCOT GENERATION-SCHEDULING IMBALANCE SERVICE 228
SCHEDULE 16
ERCOT LOAD-SCHEDULE IMBALANCE SERVICE 231
SCHEDULE 17
ERCOT SCHEDULED BACKUP SERVICE 234
SCHEDULE 18
ERCOT AUTOMATIC BACKUP SERVICE 236
SCHEDULE 19
ERCOT EMERGENCY ENERGY SERVICE 239
SCHEDULE 2013
LOSS COMPENSATION SERVICE 247
ATTACHMENT A
Form Of Service Agreement For Firm Point-To-Point Transmission Service 248
ATTACHMENT B
Form Of Service Agreement For Non-Firm Point-To-Point Transmission Service 254
ATTACHMENT C
Methodology To Assess Available Transmission Capability 257
ATTACHMENT D
Methodology for Completing a System Impact Study 258
ATTACHMENT E-1
Index of Firm Point-To-Point Transmission Service Customers Under Part II
of the Tariff 266
ATTACHMENT E-2
Index of Non-Firm Point-To-Point Transmission Service Customers
Under Part II of the Tariff 270
ATTACHMENT F
Service Agreement For Network Integration Transmission Service 275
ATTACHMENT G
Network Operating Agreement 280
ATTACHMENT H
Annual Transmission Revenue Requirement and Monthly Service Charges
For Network Integration Transmission Service 293
ATTACHMENT I
Index of Network Integration Transmission Service Customers Under Part III of
the Tariff 295
ATTACHMENT J
Form of Service Agreement for ERCOT Regional Transmission Service 296
ATTACHMENT K
Annual Transmission Revenue Requirement for ERCOT Regional
Transmission Service 307
ATTACHMENT L-1
Index of Planned ERCOT Regional Transmission Service Customers 310
ATTACHMENT L-2
Index of Unplanned ERCOT Regional Transmission Service Customers 314
ATTACHMENT M
Form of Service Agreement for ERCOT Ancillary Services 316
ATTACHMENT N
Index of ERCOT Ancillary Service Customers 320
ATTACHMENT O
North American Electric Reliability Council Transmission Loading
Relief ("TLR") Procedures - Eastern Interconnection 323
ATTACHMENT P
Generator Interconnections 356
ATTACHMENT Q
Notification of Intent to Install and Operate Generation Interconnected
With AEP Transmission System 370
ATTACHMENT R
Form 715 Transmission Planning Reliability Criteria 373
OPEN ACCESS TRANSMISSION SERVICE TARIFF
I COMMON SERVICE PROVISIONS
1 Definitions
1.1 AEP East Zone: The integrated electric utility system consisting of the generating and transmission facilities of Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Kingsport Power Company, Ohio Power Company, and Wheeling Power Company, or their successors in interest to the transmission business.
1.2 AEP West Zone: The integrated electric utility system consisting of the electric generating and transmission facilities of CPL, WTU, PSO and SWEPCO, or their successor in interest to the transmission business.
1.3 AEP Operating Companies: The public utilities that own and operate the transmission facilities in the AEP East Zone and the AEP West Zone.
1.4 Ancillary Services: Those services that are necessary to support the transmission of capacity and energy from resources to loads while maintaining reliable operation of the Transmission Provider's Transmission System in accordance with Good Utility Practice.
1.5 Annual Transmission Costs: The total annual costs for each of the AEP East Zone and AEP West Zone of the Transmission System for purposes of Network Integration Transmission Service shall be the amounts specified in Attachment H until amended by the Transmission Provider or modified by the Commission.
1.6 Application: A request by an Eligible Customer for transmission service pursuant to the provisions of the Tariff.
1.7 Chapter 25: Chapter 25, Subchapter I, Division 1 of the PUCT’s Substantive Rules, as amended from time to time.
1.8 Commission: The Federal Energy Regulatory Commission.
1.9 Completed Application: An Application that satisfies all of the information and other requirements of the Tariff, including any required deposit.
1.10 Control Area: An electric power system or combination of electric power systems to which a common automatic generation control scheme is applied in order to:
(1) match, at all times, the power output of the generators within the electric power system(s) and capacity and energy purchased from entities outside the electric power system(s), with the load within the electric power system(s);
(2) maintain scheduled interchange with other Control Areas, within the limits of Good Utility Practice;
(3) maintain the frequency of the electric power system(s) within reasonable limits in accordance with Good Utility Practice; and
(4) provide sufficient generating capacity to maintain operating reserves in accordance with Good Utility Practice.
1.11 CPL: Central Power and Light Company, or the successor in interest to the transmission business of CPL.
1.12 Curtailment: A reduction in firm or non-firm transmission service in response to a transmission capacity shortage as a result of system reliability conditions.
1.13 Delivering Party: The entity supplying capacity and energy to be transmitted at Point(s) of Receipt.
1.14 Designated Agent: Any entity that performs actions or functions on behalf of the Transmission Provider, an Eligible Customer, or the Transmission Customer required under the Tariff.
1.15 Direct Assignment Facilities: Facilities or portions of facilities that are constructed by the Transmission Provider for the sole use/benefit of a particular Transmission Customer requesting service under the Tariff. Direct Assignment Facilities shall be specified in the Service Agreement that governs service to the Transmission Customer and shall be subject to Commission approval.
1.16 ECAR: The regional reliability council operated under the East Central Area Reliability Coordination Agreement, or its successor in function.
1.17 Eligible Customer: (i) Any electric utility (including the Transmission Provider and any power marketer), Federal power marketing agency, or any person generating electric energy for sale for resale is an Eligible Customer under the Tariff. Electric energy sold or produced by such entity may be electric energy produced in the United States, Canada or Mexico. However, with respect to transmission service that the Commission is prohibited from ordering by Section 212(h) of the Federal Power Act, such entity is eligible only if the service is provided pursuant to a state requirement that the Transmission Provider offer the unbundled transmission service, or pursuant to a voluntary offer of such service by the Transmission Provider. (ii) Any retail customer taking unbundled transmission service pursuant to a state requirement that the Transmission Provider offer the transmission service, or pursuant to a voluntary offer of such service by the Transmission Provider, is an Eligible Customer under the Tariff.
1.18 ERCOT: Electric Reliability Council of Texas, which in a geographic sense refers to the area served by electric utilities that are not synchronously interconnected with electric utilities outside of the State of Texas, or its successor in function.
1.19 ERCOT Ancillary Services: Regulation Service-Up, Regulation Service-Down, Responsive Reserves, and Non-Spinning Reserves.
1.1920 ERCOT Ancillary ServicesService Date: Those Ancillary Services offered in conjunction with transmission service provided under Part IV of this Tariff. The effective July 31, 2001, or such later date at which ERCOT takes control as the Control Area Operator of the ERCOT Region under the ERCOT Protocols, and CPL and WTU are relieved of their control area operator responsibilities within ERCOT.
1.210 ERCOT Ancillary Services CustomerProtocols: An ERCOT Ancillary Services Customer shall be an entity that requires ERCOT Ancillary Services to utilize transmission service provided under Part IV of this Tariff. An ERCOT Ancillary Services Customer may designate an agent to represent the ERCOT Ancillary Services Customer in making arrangements for ERCOT Ancillary Services under Part IV of this Tariff. Shall mean the documents adopted by ERCOT, and approved by the PUCT, including any attachments or exhibits referenced in the Protocols, as amended from time to time, that contain the scheduling, operating, planning, reliability, and settlement (including customer registration) policies, rules, guidelines, procedures, standards, and criteria of ERCOT.
1.212 ERCOT ISO: The ERCOT independent system operator A Texas nonprofit corporation that has been certified by the PUCT as the Independent Organization for the ERCOT Region. established by order of the PUCT issued August 22, 1996 in PUCT Docket No. 16018.
1.22 ERCOT Power Supplier: Any electric utility that sells electricity for resale under Part IV of this Tariff.
1.23 ERCOT Regional Transmission Service: The Transmission Service offered under Part IV of this Tariff.
1.24 ERCOT Regional Transmission Service Customer: An Eligible Customer taking ERCOT Regional Transmission Service under Part IV of this Tariff.
1.25 ERCOT Transmission Network: The interconnected bulk power delivery system comprised of the transmission systems located and operated in ERCOT, including the CPL/WTU Transmission System.
1.26 Facilities Study: An engineering study conducted by the Transmission Provider to determine the required modifications to the Transmission Provider's Transmission System, or the ERCOT Transmission Network, including the cost and scheduled completion date for such modifications, that will be required to provide the requested transmission service.
1.27 Firm Point-To-Point Transmission Service: Transmission Service under this Tariff that is reserved and/or scheduled between specified Points of Receipt and Delivery pursuant to Part II of this Tariff.
1.28 Good Utility Practice: Any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition. Good Utility Practice is not intended to be limited to the optimum practice, method, or act to the exclusion of all others, but rather to be acceptable practices, methods, or acts generally accepted in the region.
1.29 High-Voltage Direct Current Facilities (or "HVDC Facilities"): Either (i) the North Interconnection, consisting of high voltage back-to-back converters and related facilities on either side of the ERCOT-SPP border at Oklaunion, Texas, having a nominal capacity of 220 MW, or (ii) the East Interconnection consisting of: (a) a 345 kV alternating current (AC) switchyard facility at the TU Electric Monticello generating station necessary for the interconnection of the TU Electric AC electric system with the Welsh-Monticello Line; (b) the Welsh-Monticello Line, which is a 345 kV AC transmission line between the Monticello Switchyard Facility described in the preceding clause and the High Voltage Direct Current (HVDC) Terminal described in the succeeding clause; (c) the HVDC Terminal, consisting of high voltage back-to-back converters, having a nominal capacity of 600 MW, of which the Transmission Provider and its affiliates own 300 MW, and related facilities and the land on which such facilities are located; and (d) a 345 kV AC switchyard facility at the SWEPCO Welsh generating station necessary for the interconnection of the SWEPCO AC electric system with such HVDC Terminal, or (iii) both the North Interconnection and the East Interconnection.
1.30 HLP: Houston Lighting & Power Company.
1.310 Interconnection Agreement: An agreement between an Eligible Customer that owns electric facilities in ERCOT and one or more of the ERCOT Transmission Providers that sets forth requirements for physical connection and interconnected operations. A Transmission Customer that owns electrical facilities in ERCOT must have such an agreement with each of the ERCOT Transmission Providers to which the Transmission Customer is physically connected.
1.321 Interruption: A reduction in non-firm transmission service due to economic reasons pursuant to Section 14.7.
1.332 Load Ratio Share: Ratio of a Transmission Customer's Network Load to the Transmission Provider's total load computed in accordance with Attachment H and Sections 34.2 and 34.3 of the Network Integration Transmission Service under Part III of the Tariff.
1.34 Load Serving Entity: Any electric utility operating in ERCOT that serves Native Load Customers within ERCOT.
1.353 Load Shedding: The systematic reduction of system demand by temporarily decreasing load in response to transmission system or area capacity shortages, system instability, or voltage control considerations under Part III of the Tariff.
1.364 Long-Term Firm Point-To-Point Transmission Service: Firm Point-To-Point Transmission Service under Part II of the Tariff with a term of one year or more.
1.3735 Native Load Customers: The wholesale and retail power customers of the Transmission Provider on whose behalf the Transmission Provider, by statute, franchise, regulatory requirement, or contract, has undertaken an obligation to construct and operate the Transmission Provider's system to meet the reliable electric needs of such customers. or the wholesale and retail power customers of a Load Serving Entity on whose behalf the Load Serving Entity, by statute, franchise, regulatory requirement, or contract has undertaken an obligation to plan, construct and operate the Load Serving Entity's system to meet the reliable electric needs of such customers. For purposes of Part IV of this Tariff, Native Load Customers will not include load served outside of ERCOT.
1.3836 NERC: North American Electric Reliability Council, or its successor in function.
1.3937 Network Customer: An entity receiving transmission service pursuant to the terms of the Transmission Provider's Network Integration Transmission Service under Part III of the Tariff.
1.4038 Network Integration Transmission Service: The transmission service provided under Part III of the Tariff.
1.4139 Network Load: The load that a Network Customer designates for Network Integration Transmission Service under Part III of the Tariff. The Network Customer's Network Load shall include all load served by the output of any Network Resources designated by the Network Customer. A Network Customer may elect to designate less than its total load as Network Load but may not designate only part of the load at a discrete Point of Delivery. Where a Eligible Customer has elected not to designate a particular load at discrete points of delivery as Network Load, the Eligible Customer is responsible for making separate arrangements under Part II of the Tariff for any Point-To-Point Transmission Service that may be necessary for such non-designated load.
1.420 Network Operating Agreement: An executed agreement that contains the terms and conditions under which the Network Customer shall operate its facilities and the technical and operational matters associated with the implementation of Network Integration Transmission Service under Part III of the Tariff.
1.431 Network Operating Committee: A group made up of representatives from the Network Customer(s) and the Transmission Provider established to coordinate operating criteria and other technical considerations required for implementation of Network Integration Transmission Service under Part III of this Tariff.
1.442 Network Resource: Any designated generating resource owned, purchased or leased by a Network Customer under the Network Integration Transmission Service Tariff. Network Resources do not include any resource, or any portion thereof, that is committed for sale to third parties or otherwise cannot be called upon to meet the Network Customer's Network Load on a non-interruptible basis.
1.453 Network Upgrades: Modifications or additions to transmission-related facilities that are integrated with and support the Transmission Provider's overall Transmission System for the general benefit of all users of such Transmission System.
1.464 Non-Firm Point-To-Point Transmission Service: Point-To-Point Transmission Service under the Tariff that is reserved and scheduled on an as-available basis and is subject to Curtailment or Interruption as set forth in Section 14.7 under Part II of this Tariff. Non-Firm Point-To-Point Transmission Service is available on a stand-alone basis for periods ranging from one hour to one year.
1.4745 Open Access Same-Time Information System (OASIS): The information system and standards of conduct contained in Part 37 of the Commission's regulations and all additional requirements implemented by subsequent Commission orders dealing with OASIS. OASIS means the AEP East Zone OASIS, the SPP OASIS and the ERCOT OASIS, as applicable.
1.4846 Part I: Tariff Definitions and Common Service Provisions contained in Sections 21 through 12.
1.4947 Part II: Tariff Sections 13 through 27 pertaining to Point-To-Point Transmission Service in conjunction with the applicable Common Service Provisions of Part I and appropriate Schedules and Attachments.
1.5048 Part III: Tariff Sections 28 through 35 pertaining to Network Integration Transmission Service in conjunction with the applicable Common Service Provisions of Part I and appropriate Schedules and Attachments.
1.5149 Part IV: Tariff Sections 36 through 43 41 pertaining to the use of the CPL/WTU Transmission System operated in ERCOT in conjunction with the use by a Transmission Customer of the ERCOT Transmission Network to serve load within ERCOT and in conjunction with the applicable Common Service Provisions of Part I and the applicable Schedules and Attachments.
1.520 Parties: The Transmission Provider and the Transmission Customer receiving service under the Tariff.
1.53 Planned Resource: Any generation resource owned, controlled or purchased by an ERCOT Power Supplier or Load Serving eEntity )and designated as a Planned Resource for the purpose of serving load located in ERCOT.
1.54 Planned Service: The use by a Transmission Customer of the ERCOT Transmission Network for the delivery of power and energy from Planned Resources to loads within ERCOT pursuant to Part IV of this Tariff.
1.551 Point(s) of Delivery: Point(s) on the Transmission Provider's Transmission System where capacity and energy transmitted by the Transmission Provider will be made available to the Receiving Party under Part II of the Tariff. The Point(s) of Delivery shall be specified in the Service Agreement for Long-Term Firm Point-To-Point Transmission Service.
1.562 Point(s) of Receipt: Point(s) of interconnection on the Transmission Provider's Transmission System where capacity and energy will be made available to the Transmission Provider by the Delivering Party under Part II of the Tariff. The Point(s) of Receipt shall be specified in the Service Agreement for Long-Term Firm Point-To-Point Transmission Service.
1.573 Point-To-Point Transmission Service: The reservation and transmission of capacity and energy on either a firm or non-firm basis from the Point(s) of Receipt to the Point(s) of Delivery under Part II of the Tariff.
1.584 Power Purchaser: The entity that is purchasing the capacity and energy to be transmitted under the Tariff.
1.5955 PSO: Public Service Company of Oklahoma, or the successor in interest to the transmission business of PSO.
1.6056 PUCT: Public Utility Commission of Texas.
1.57 QSE: A person qualified by the ERCOT IO to submit schedules to and settle payments with, the ERCOT IO.
1.6158 Receiving Party: The entity receiving the capacity and energy transmitted by the Transmission Provider to Point(s) of Delivery.
1.6259 Regional Transmission Group (RTG): A voluntary organization of transmission owners, transmission users and other entities approved by the Commission to efficiently coordinate transmission planning (and expansion), operation and use on a regional (and interregional) basis.
1.6360 Reserved Capacity: The maximum amount of capacity and energy that the Transmission Provider agrees to transmit for the Transmission Customer over the Transmission Provider's Transmission System between the Point(s) of Receipt and the Point(s) of Delivery under Part II of the Tariff. Reserved Capacity shall be expressed in terms of whole megawatts on a sixty (60) minute interval (commencing on the clock hour) basis.
1.613A Retail Electric Provider (REP): A person certified by a state electric utility regulatory authority to sell electric energy to retail customers.
1.642 Service Agreement: The initial agreement and any amendments or supplements thereto entered into by the Transmission Customer and the Transmission Provider for service under the Tariff.
1.653 Service Commencement Date: The date the Transmission Provider begins to provide service pursuant to the terms of an executed Service Agreement, or the date the Transmission Provider begins to provide service in accordance with Section 15.3, Section 29.1, or Section 38.86 under the Tariff.
1.664 Short-Term Firm Point-To-Point Transmission Service: Firm Point-To-Point Transmission Service under Part II of the Tariff with a term of less than one year.
1.6765 SPP: Southwest Power Pool, or its successor in function.
1.6866 SWEPCO: Southwestern Electric Power Company, or the successor in interest to the transmission business of SWEPCO.
1.6967 System Impact Study: An assessment by the Transmission Provider of (i) the adequacy of the Transmission System to accommodate a request for either Firm Point-To-Point Transmission Service, Network Integration Transmission Service, or Planned ERCOT Regional Transmission Service and (ii) whether any additional costs may be incurred in order to provide transmission service.
1.7068 Third-Party Sale: Any sale for resale in interstate commerce to a Power Purchaser that is not designated as part of Network Load under the Network Integration Transmission Service.
1.7169 Transmission Customer: Any Eligible Customer (or its Designated Agent) that (i) executes a Service Agreement, or (ii) requests in writing that the Transmission Provider file with the Commission, a proposed unexecuted Service Agreement to receive transmission service under Part II of the Tariff. This term is used in the Part I Common Service Provisions to include customers receiving transmission service under Part II, Part III or Part IV of this Tariff.
1.7270 Transmission Provider: The public utilities (or their Designated Agent) that own, control, or operate facilities used for the transmission of electric energy in interstate commerce and provide transmission service under the Tariff; provided, however, that in the case of service provided on the ERCOT Transmission Network under Part IV of this Tariff, the term refers in the plural form to all transmitting utilities that operate in ERCOT, when preceded by an indefinite article the term in the singular form refers to any such transmitting utility and when preceded by the definite article the term in the singular form refers collectively to CPL and WTU.
1.731 Transmission Provider's Monthly Transmission System Peak: The maximum firm usage of the Transmission Provider's Transmission System in a calendar month.
1.742 Transmission Service: Point-To-Point Transmission Service provided under Part II of the Tariff on a firm and non-firm basis.
1.753 Transmission System: (1) The facilities owned, controlled or operated in ERCOT at or above 60 kilovolts owned, controlled, operated or supported by a Transmission Provider that are used to provide transmission service in ERCOT under Part IV of this Tariff, including the HVDC Facilities (such facilities of CPL and WTU being referred to herein collectively as the "CPL/WTU Transmission System" and all such facilities in the aggregate being referred to herein as the "ERCOT Transmission Network" as that term is defined in Section 1.245 of this Tariff); or (2) the facilities owned, controlled or operated by the Transmission Provider that are used to provide transmission service under Part II and Part III of the Tariff (such facilities being referred to herein collectively as the "Transmission System").
1.764 TXU Electric: TXU Electric Company.
1.77 Unplanned Resource: Any generation resource owned, controlled or purchased by an ERCOT Power Supplier or Load Serving Entity, used to serve loads within ERCOT and not designated as a Planned Resource.
1.78 Unplanned Service: The use by a Transmission Customer of the ERCOT Transmission Network for delivery of power and energy from Unplanned Resources to loads within ERCOT under Part IV of this Tariff.
1.7975 WTU: West Texas Utilities Company, or its successor in interest to the transmission business of WTU.
2 Initial Allocation and Renewal Procedures
2.1 Not Applicable.
2.2 Reservation Priority For Existing Firm Service Customers: Existing firm service customers (wholesale requirements and transmission-only, with a contract term of one year or more and retail, irrespective of term), have the right to continue to take transmission service from the Transmission Provider when the contract expires, rolls over or is renewed. This transmission reservation priority is independent of whether the existing customer continues to purchase capacity and energy from the Transmission Provider or elects to purchase capacity and energy from another supplier. If at the end of the contract term, the Transmission Provider's Transmission System cannot accommodate all of the requests for transmission service the existing firm service customer must agree to accept a contract term at least equal to a competing request by any new Eligible Customer and to pay the current just and reasonable rate, as approved by the Commission, for such service. This transmission reservation priority for existing firm service customers is an ongoing right that may be exercised at the end of all firm contract terms of one year or longer.
3 Ancillary Services
Ancillary Services are needed with transmission service to maintain reliability within and among the Control Areas affected by the transmission service. The Transmission Provider is required to provide (or offer to arrange with the local Control Area operator as discussed below), and the Transmission Customer is required to purchase, the following Ancillary Services (i) System Scheduling, System Control and Dispatch, and (ii) System Reactive Supply and Voltage Control from Generation Sources.
The Transmission Provider is required to offer to provide (or offer to arrange with the local Control Area operator as discussed below) the following Ancillary Services only to the Transmission Customer serving load within any of the Transmission Provider's Control Areas: (i) System Regulation and Frequency Response, (ii) System Energy Imbalance, (iii) System Operating Reserve - Spinning Reserve Service (ECAR and SPP) or Responsive Reserve Service (ERCOT), and (iv) System Operating Reserve - Supplemental Reserve Service (ECAR and SPP) or Spinning Reserve Service (ERCOT). The Transmission Customer serving load within one of the Transmission Provider's Control Areas is required to acquire these Ancillary Services, whether from the Transmission Provider, from a third party, or by self-supply. The Transmission Provider is also required to provide System Load Following Service in connection with transactions that involve transfers over the HVDC Facilities.
The Transmission Customer may not decline the Transmission Provider's offer of Ancillary Services unless it demonstrates that it has acquired the Ancillary Services from another source. The Transmission Customer must list in its Application which Ancillary Services it will purchase from the Transmission Provider.
If the Transmission Provider is a public utility providing transmission service but is not a Control Area operator, it may be unable to provide some or all of the Ancillary Services. In this case, the Transmission Provider can fulfill its obligation to provide Ancillary Services outside ERCOT by acting as the Transmission Customer's agent to secure these Ancillary Services from the Control Area operator. Where applicable, tThe Transmission Customer may elect to (i) have the Transmission Provider act as its agent, (ii) secure the Ancillary Services directly from the Control Area operator, or (iii) secure the Ancillary Services (discussed in Schedules 3-A, 3-B, 4, 4A, 5 and 6) from a third party or by self-supply when technically feasible. The Transmission Provider shall specify the rate treatment and all related terms and conditions in the event of an unauthorized use of Ancillary Services by the Transmission Customer.
Effective on and after the ERCOT Operation Date, Transmission Customers taking service under Part IV of this Tariff to serve load in ERCOT must arrange Ancillary Services in ERCOT consistent with the ERCOT Protocols. Through December 31, 2001, Retail Electric Providers (REPs) taking transmission service under Part IV to deliver power and energy to retail customers connected to the distribution or transmission facilities of CPL or WTU in ERCOT shall have the option to purchase the ERCOT Ancillary Services contained in Service Schedules 9 through 12. Until the earlier of December 31, 2001 or the expiration of a customer's full or partial requirements service agreement, Service Schedules 9 through 12 shall also apply to those wholesale customers of CPL and WTU with such service agreements that provide for the Customer to take unbundled ancillary services. In all other cases Transmission Customers serving load in ERCOT will obtain ERCOT Ancillary Services through the markets for Ancillary Services operated by ERCOT.
The specific Ancillary Services, prices and/or compensation methods are described on the Schedules that are attached to and made a part of the Tariff. Three principal requirements apply to discounts for Ancillary Services provided by the Transmission Provider in conjunction with its provision of transmission service as follows: (1) any offer of a discount made by the Transmission Provider must be announced to all Eligible Customers solely by posting on the OASIS, (2) any customer-initiated requests for discounts (including requests for use by one's wholesale merchant or an affiliate's use) must occur solely by posting on the OASIS, and (3) once a discount is negotiated, details must be immediately posted on the OASIS. A discount agreed upon for an Ancillary Service must be offered for the same period to all Eligible Customers on the Transmission Provider's system. Sections 3.1 through 3.6 below list the seven six Ancillary Services that FERC has ordered the Transmission Provider to provide in connection with Transmission Service provided under Part II or Part III of this Tariff. Sections 3.7 through 3.17 below list the eleven ERCOT Ancillary Services that CPL and WTU offer to provide in connection with transmission service provided under Part IV of this Tariff.
3.1 System Scheduling, System Control and Dispatch Service: The rates and/or methodology are described in Schedule 1.
3.2 System Reactive Supply and Voltage Control from Generation Sources Service: The rates and/or methodology are described in Schedule 2.
3.3-A System Regulation and Frequency Response Service: Where applicable, the rates and/or methodology are described in Schedule 3-A.
3.3-B System Load Following Service: Where applicable, the rates and/or methodology are described in Schedule 3-B.
3.4 System Energy Imbalance Service: Where applicable, the rates and/or methodology are described in Schedule 4A.
3.5 System Operating Reserve - Spinning Reserve Service (ECAR and SPP)or Responsive Reserve Service (ERCOT): Where applicable, the rates and/or methodology are described in Schedule 5.
3.6 System Operating Reserve - Supplemental Reserve Service (ECAR and SPP)or Spinning Reserve Service (ERCOT): Where applicable, the rates and/or methodology are described in Schedule 6.
3.7 ERCOT Responsive Reserve Service: Where applicable, the service, rates and/or methodology are described in Schedule 9.
3.8 ERCOT Spinning Reserve Service: Where applicable, the service, rates and/or methodology are described in Schedule 10.
3.9 ERCOT Static Scheduling Service: Where applicable, the service, rates and/or methodology are described in Schedule 11.
3.10 ERCOT Dynamic Scheduling Service: Where applicable, the service, rates and/or methodology are described in Schedule 12.
3.11 ERCOT Load Following Service: Where applicable, the service, rates and/or methodology are described in Schedule 13.
3.12 ERCOT Load Regulation Service: Where applicable, the service, rates and/or methodology are described in Schedule 14.
3.13 ERCOT Generation Schedule Imbalance Service: Where applicable, the service, rates and/or methodology are described in Schedule 15.
3.14 ERCOT Load Schedule Imbalance Service: Where applicable, the service, rates and/or methodology are described in Schedule 16.
3.15 ERCOT Schedule Backup Service: Where applicable, the service, rates and/or methodology are described in Schedule 17.
3.16 ERCOT Automatic Backup Service: Where applicable, the service, rates and/or methodology are described in Schedule 18.
3.17 ERCOT Emergency Energy Service: Where applicable, the service, rates and/or methodology are described in Schedule 19.
4 Open Access Same-Time Information System (OASIS)
Terms and conditions regarding the Open Access Same-Time Information System and standards of conduct are set forth in 18 C.F.R. § 37 of the Commission's regulations (Open Access Same-Time Information System and Standards of Conduct for Public Utilities). In the event available transmission capability as posted on the OASIS is insufficient to accommodate a request for firm transmission service under Part II of this Tariff or Network Integration Transmission Service under Part III of this Tariff, additional studies may be required as provided by this Tariff pursuant to Sections 19 and 32 of this Tariff. In the event available transmission capability as posted on the ERCOT OASIS is insufficient to accommodate a request for Planned Service under Part IV of this Tariff, additional studies may be required pursuant to Section 40 of this Tariff. Transmission Customers requesting service under Parts II and III that involves the use of CPL and WTU transmission facilities as well as parts of the Transmission System that are operated in the SPP or ECAR must notify the ERCOT OASIS as well as the SPP OASIS and the AEP East Zone OASIS, as applicable. Transmission Customers requesting service under Part IV of this Tariff must notify the ERCOT OASIS.
5 Upgrades to HVDC Facilities
Whenever planning is undertaken by AEP to increase the capacity of the HVDC Facilities, but at intervals of no more than every three years after June 30, 1983, with respect to the North Interconnection, and after June 30, 1989, with respect to the East Interconnection, until in either case June 30, 2004, electric utilities in ERCOT and the SPP will be given the opportunity to participate in the planning of increases in the capacity of the HVDC Facilities and of participating in the ownership of any incremental capacity added, provided that each party that wishes to participate pays its pro rata share of all costs of constructing the HVDC Facilities in which it wishes to participate and undertakes to pay its pro rata share of the costs of operating and maintaining such HVDC Facilities and agrees further to be bound by the terms and conditions of the agreement between owners of such HVDC Facilities.
6 Reciprocity
A Transmission Customer receiving transmission service under this Tariff agrees to provide comparable transmission service that it is capable of providing to the Transmission Provider on similar terms and conditions over facilities used for the transmission of electric energy owned, controlled or operated by the Transmission Customer and over facilities used for the transmission of electric energy owned, controlled or operated by the Transmission Customer's corporate affiliates. A Transmission Customer that is a member of a power pool or Regional Transmission Group also agrees to provide comparable transmission service to the members of such power pool and Regional Transmission Group on similar terms and conditions over facilities used for the transmission of electric energy owned, controlled or operated by the Transmission Customer and over facilities used for the transmission of electric energy owned, controlled or operated by the Transmission Customer's corporate affiliates.
This reciprocity requirement applies not only to the Transmission Customer that obtains transmission service under the Tariff, but also to all parties to a transaction that involves the use of transmission service under the Tariff, including the power seller, buyer and any intermediary, such as a power marketer. This reciprocity requirement also applies to any Eligible Customer that owns, controls or operates transmission facilities that uses an intermediary, such as a power marketer, to request transmission service under the Tariff. If the Transmission Customer does not own, control or operate transmission facilities, it must include in its Application a sworn statement of one of its duly authorized officers or other representatives that the purpose of its Application is not to assist an Eligible Customer to avoid the requirements of this provision. Without limiting the generality of the foregoing, a Transmission Customer that has on file with the PUCT a transmission tariff that meets the requirements of Chapter 25 of the PUCT's Substantive Rules shall be deemed to satisfy this reciprocity requirement.
7 Billing and Payment
7.1 Billing Procedure: Within a reasonable time after the first day of each month, the Transmission Provider shall submit an invoice to the Transmission Customer for the charges for all services furnished under the Tariff during the preceding month. The invoice rendered for service under Part II or Part III of this Tariff shall be paid by the Transmission Customer within twenty (20) days of receipt. The invoice rendered for service under Part IV of this Tariff shall be paid by the ERCOT Regional Transmission Customer within twenty (20) days after the date of the invoice the time period specified Chapter 25. All payments shall be made in immediately available funds payable to the Transmission Provider or by wire transfer to a bank named by the Transmission Provider.
7.2 Interest on Unpaid Balances: Interest on any unpaid amounts (including amounts placed in escrow) for service under Part II and Part III shall be calculated in accordance with the methodology specified for interest on refunds in the Commission's regulations at 18 C.F.R. § 35.19a(a)(2)(iii). Interest on unpaid amounts for service provided under Part IV, shall be calculated pursuant to Chapter 25. Interest on delinquent amounts shall be calculated from the due date of the bill to the date of payment. When payments are made by mail, bills shall be considered as having been paid on the date of receipt by the Transmission Provider.
7.3 Customer Default: In the event the Transmission Customer fails, for any reason other than a billing dispute as described below, to make payment to the Transmission Provider on or before the due date as described above, and such failure of payment is not corrected within thirty (30) calendar days after the Transmission Provider notifies the Transmission Customer to cure such failure, a default by the Transmission Customer shall be deemed to exist. Upon the occurrence of a default, the Transmission Provider may initiate a proceeding with the Commission to terminate service but shall not terminate service until the Commission so approves any such request. In the event of a billing dispute between the Transmission Provider and the Transmission Customer, the Transmission Provider will continue to provide service under the Service Agreement as long as the Transmission Customer (i) continues to make all payments not in dispute, and (ii) pays into an independent escrow account the portion of the invoice in dispute, pending resolution of such dispute. If the Transmission Customer fails to meet these two requirements for continuation of service, then the Transmission Provider may provide notice to the Transmission Customer of its intention to suspend service in sixty (60) days, in accordance with Commission policy.
8 Accounting for the Transmission Provider's Use of the Tariff
The Transmission Provider shall record the following amounts, as outlined below.
8.1 Transmission Revenues: Include in a separate operating revenue account or subaccount the revenues it receives from Transmission Service when making Third-Party Sales under Part II of the Tariff.
8.2 Study Costs and Revenues: Include in a separate transmission operating expense account or subaccount, costs properly chargeable to expense that are incurred to perform any System Impact Studies or Facilities Studies which the Transmission Provider conducts to determine if it must construct new transmission facilities or upgrades necessary for its own uses, including making Third-Party Sales under the Tariff; and include in a separate operating revenue account or subaccount the revenues received for System Impact Studies or Facilities Studies performed when such amounts are separately stated and identified in the Transmission Customer's billing under the Tariff.
9 Regulatory Filings
Nothing contained in the Tariff or any Service Agreement shall be construed as affecting in any way the right of the Transmission Provider to unilaterally make application to the Commission for a change in rates, terms and conditions, charges, classification of service, Service Agreement, rule or regulation under Section 205 of the Federal Power Act and pursuant to the Commission's rules and regulations promulgated thereunder.
Nothing contained in the Tariff or any Service Agreement shall be construed as affecting in any way the ability of any Party receiving service under the Tariff to exercise its rights under the Federal Power Act and pursuant to the Commission's rules and regulations promulgated thereunder.
10 Force Majeure and Indemnification
10.1 Force Majeure: An event of Force Majeure means any act of God, labor disturbance, act of the public enemy, war, insurrection, riot, fire, storm or flood, explosion, breakage or accident to machinery or equipment, any Curtailment, order, regulation or restriction imposed by governmental military or lawfully established civilian authorities, or any other cause beyond a Party's control. A Force Majeure event does not include an act of negligence or intentional wrongdoing. Neither the Transmission Provider nor the Transmission Customer will be considered in default as to any obligation under this Tariff if prevented from fulfilling the obligation due to an event of Force Majeure. However, a Party whose performance under this Tariff is hindered by an event of Force Majeure shall make all reasonable efforts to perform its obligations under this Tariff.
10.2 Indemnification: The Transmission Customer shall at all times indemnify, defend, and save the Transmission Provider harmless from, any and all damages, losses, claims, including claims and actions relating to injury to or death of any person or damage to property, demands, suits, recoveries, costs and expenses, court costs, attorney fees, and all other obligations by or to third parties, arising out of or resulting from the Transmission Provider's performance of its obligations under this Tariff on behalf of the Transmission Customer, except in cases of negligence or intentional wrongdoing by the Transmission Provider.
11 Creditworthiness
For the purpose of determining the ability of the Transmission Customer to meet its obligations related to service hereunder, the Transmission Provider may require reasonable credit review procedures, which may include but shall not be limited to, verification that the Transmission Customer is not operating under any state or federal bankruptcy laws, is not subject to the uncertainty of pending liquidation or regulatory proceedings in state or federal courts, and no significant collection lawsuits or judgments are outstanding that would seriously affect the Transmission Customer's ability, in the Transmission Provider's determination, to remain solvent. As part of this process, the Transmission Customer may be required to furnish the Transmission Provider with the Transmission Customer's financial reports and/or its reports to shareholders. Creditworthiness requirements for retail electric providers in ERCOT will be governed by Chapter 25 under certification for retail electric providers.
Specifically, the Transmission Customer will be considered creditworthy upon satisfying one of the following conditions:
(a) At the time it enters into a transaction and throughout the term thereof, the Transmission Customer provides the Transmission Provider evidence that its long-term unsecured debt securities are rated BBB or better by Standard & Poor's Corporation, or Baa2 or better by Moody's Investor Service, or that its common stock is rated B+ or better by Standard and Poor's Corporation, it being the Transmission Customer's obligation to notify the Transmission Provider of any adverse changes in such ratings.
(b) The Transmission Customer either prepays for service or provides an unconditional letter of credit for an amount equal to or greater than the total charges for the term of the transaction. Any letter of credit provided to the Transmission Provider must be issued by a commercial bank or financial institution located in the United States or Canada whose long-term unsecured debt securities are rated A or better by Standard & Poor's Corporation or A2 or better by Moody's Investor Service, Inc., or comparable rating by another rating service acceptable to the Transmission Provider in its sole discretion.
(c) The Transmission Customer has, in the Transmission Provider's sole discretion, a satisfactory long-term payment history with any of the AEP Operating Companies.
(d) The Transmission Provider receives a written guarantee from the Transmission Customer's parent company (if applicable) that the parent will be responsible unconditionally for all financial obligations associated with the transaction, and the Transmission Customer's parent company qualifies as creditworthy pursuant to one or more of the provisions of this section.
(e) The Transmission Customer is a borrower from the Rural Utilities Service and has a Times Interest Earned Ratio (TIER) of 1.05 or better and a Debt Service Coverage Ratio (DSC) of 1.00 or better in the most recent calendar year, or an average TIER of 1.05 or better and average DSC of 1.00 or better achieved in the two best years out of the three most recent calendar years.
12 Dispute Resolution Procedures
12.1 Internal Dispute Resolution Procedures: Any dispute between a Transmission Customer and the Transmission Provider involving transmission service under the Tariff (excluding applications for rate changes or other changes to the Tariff, or to any Service Agreement entered into under the Tariff, which shall be presented directly to the Commission for resolution) shall be referred to a designated senior representative of the Transmission Provider and a senior representative of the Transmission Customer for resolution on an informal basis as promptly as practicable. In the event the designated representatives are unable to resolve the dispute within thirty (30) days, or such other period as the Parties may agree upon, by mutual agreement, such dispute may be submitted to arbitration and resolved in accordance with the arbitration procedures set forth below.
12.2 External Arbitration Procedures: Any arbitration initiated under the Tariff with regards to service under Part II or Part III shall be conducted before a single neutral arbitrator appointed by the Parties. If the Parties fail to agree upon a single arbitrator within ten (10) days of the referral of the dispute to arbitration, each Party shall choose one arbitrator who shall sit on a three-member arbitration panel. The two arbitrators so chosen shall within twenty (20) days select a third arbitrator to chair the arbitration panel. In either case, the arbitrators shall be knowledgeable in electric utility matters, including electric transmission and bulk power issues, and shall not have any current or past substantial business or financial relationships with any party to the arbitration (except prior arbitration). The arbitrator(s) shall provide each of the Parties an opportunity to be heard and, except as otherwise provided herein, shall generally conduct the arbitration in accordance with the Commercial Arbitration Rules of the American Arbitration Association and any applicable Commission regulations or Regional Transmission Group rules.
12.3 Arbitration Decisions: Unless otherwise agreed, the arbitrator(s) contemplated by Section 12.2 of this Tariff shall render a decision within ninety (90) days of appointment and shall notify the Parties in writing of such decision and the reasons therefor. The arbitrator(s) shall be authorized only to interpret and apply the provisions of the Tariff and any Service Agreement entered into under the Tariff and shall have no power to modify or change any of the above in any manner. The decision of the arbitrator(s) shall be final and binding upon the Parties, and judgment on the award may be entered in any court having jurisdiction. The decision of the arbitrator(s) may be appealed solely on the grounds that the conduct of the arbitrator(s), or the decision itself, violated the standards set forth in the Federal Arbitration Act and/or the Administrative Dispute Resolution Act. The final decision of the arbitrator must also be filed with the Commission if it affects jurisdictional rates, terms and conditions of service or facilities.
12.4 Costs: Each Party shall be responsible for its own costs incurred during the arbitration process and for the following costs, if applicable: (A) the cost of the arbitrator chosen by the Party to sit on the three member panel and one half of the cost of the third arbitrator chosen; or (B) one half the cost of the single arbitrator jointly chosen by the Parties.
12.5 Arbitration under Part IV: Any arbitration initiated with regard to service under Part IV of this Tariff shall be conducted under the arbitration procedures set forth in the ERCOT Protocols.
12.56 Rights Under The Federal Power Act: Nothing in this section shall restrict the rights of any party to file a Complaint with the Commission under relevant provisions of the Federal Power Act.
II POINT-TO-POINT TRANSMISSION SERVICE
Preamble
The Transmission Provider will provide Firm and Non-Firm Point-To-Point Transmission Service pursuant to the applicable terms and conditions set forth in this Tariff and in the Transmission Customer’s Service Agreement; provided that other than Point-to-Point Transmission Service that is grandfathered under Sections 1.14a and 37.4 of the SPP Open Access Transmission Service Tariff for service offered by the SPP (SPP Tariff), the use of the portion of the Transmission System located in the SPP for Firm and Non-Firm Point-to-Point Transmission Service shall be arranged for and taken under the SPP Tariff in accordance with the applicable terms and conditions of the SPP Tariff. Point-to-Point Transmission Service is for the receipt of capacity and energy at designated Point(s) of Receipt and the transmission of such capacity and energy to designated Point(s) of Delivery.
Charges for Point-to-Point Transmission Service, if applicable, are based on whether the Point of Delivery is located in the AEP East Zone or the AEP West Zone. To accomplish the delivery of energy from the Point of Receipt to the Point of Delivery (or beyond the Point of Delivery to the load ultimately to be served with the energy to be transmitted), the Transmission Customer may also be required to arrange and pay for service under the transmission tariffs of other transmission providers, including without limitation the SPP Tariff.
Delivery to a Point of Delivery in the AEP East Zone
1. Point-to-Point Transmission Service to a Point of Delivery in the AEP East Zone
shall be subject to an East Zone charge under Schedule 7 or 8 of the Tariff, regardless of the location of the Point of Receipt.
Delivery to a Delivery Point in the AEP West Zone for Transactions that are Grandfathered Under the SPP Tariff
2. Any Short-Term Firm or Non-Firm Point-to-Point Transmission Service the arrangements for which were accepted and confirmed prior to June 1, 1998 and any Long-Term Firm Point-to-Point Transmission Service provided under a service agreement executed prior to April 1, 2000, and that, in either case, makes use of the portion of the Transmission System located in the SPP are grandfathered under the SPP Tariff. Such grandfathered transactions shall continue to be taken under the rates, terms and conditions of Part II of this Tariff for Point-to-Point Transmission Service to a Point of Delivery in the AEP West Zone and the Transmission Customer shall remain liable to the Transmission Provider for an AEP West Zone charge under Schedule 7 or Schedule 8 of the Tariff for such transmission service.
Delivery to a Point of Delivery in the West Zone for Transactions that are Not Grandfathered Under the SPP Tariff
Into SPP from the AEP East Zone
3. A Transmission Customer that takes Point-to-Point Transmission Service under the SPP Tariff to a Point of Delivery in the AEP West Zone portion of the SPP from a Point of Receipt in the AEP East Zone shall not be liable to the Transmission Provider for charges under Schedule 7 or Schedule 8 of this Tariff.
Into ERCOT from the AEP East Zone or from the SPP
4. A Transmission Customer that takes Point-to-Point Transmission Service to a Point of Delivery in ERCOT from a Point of Receipt in the AEP East Zone or in the SPP shall be liable to the Transmission Provider for charges under Part IV of this Tariff, and not under Schedule 7 or Schedule 8 of this Tariff, if it is a Load Serving Entity and if the energy to be delivered is to be used to serve load in ERCOT.
Through ERCOT from the AEP East Zone or the AEP West Zone
5. A Transmission Customer that takes Point-to-Point Transmission Service from a Point of Receipt in the AEP East Zone, in the SPP or in ERCOT to a Point of Delivery in ERCOT for ultimate delivery outside of ERCOT (e.g., to Mexico) shall be liable to the Transmission Provider for an AEP West Zone charge under Schedule 7 or Schedule 8 of this Tariff.
Into/through the SPP from/through ERCOT
6. A Transmission Customer that takes Point-to-Point Transmission Service to a Point of Delivery in the SPP from a Point of Receipt in ERCOT shall be liable to the Transmission Provider for a West Zone charge under Schedule 7 or Schedule 8 of this Tariff.
Within SPP Only
7. A Transmission Customer that takes Point-to-Point Transmission Service from a Point of Receipt in the PSO/SWEPCO control area for delivery to a Point of Delivery in the SPP for ultimate delivery in the SPP or outside the SPP (other than to or through ERCOT or the AEP East Zone) shall not be subject to any charges under Schedule 7 or Schedule 8 of this Tariff.
13 Nature of Firm Point-To-Point Transmission Service
13.1 Term: The minimum term of Firm Point-To-Point Transmission Service shall be one day and the maximum term shall be specified in the Service Agreement.
13.2 Reservation Priority: Long-Term Firm Point-To-Point Transmission Service shall be available on a first-come, first-served basis, i.e., in the chronological sequence in which each Transmission Customer has reserved service. Reservations for Short-Term Firm Point-To-Point Transmission Service will be conditional based upon the length of the requested transaction. If the Transmission System becomes oversubscribed, requests for longer term service may preempt requests for shorter term service up to the following deadlines: one day before the commencement of daily service, one week before the commencement of weekly service, and one month before the commencement of monthly service. Before the conditional reservation deadline, if available transmission capability is insufficient to satisfy all Applications, an Eligible Customer with a reservation for shorter term service has the right of first refusal to match any longer term reservation before losing its reservation priority. A longer term competing request for Short-Term Firm Point-To-Point Transmission Service will be granted if the Eligible Customer with the right of first refusal does not agree to match the competing request within 24 hours (or earlier if necessary to comply with the scheduling deadlines provided in section 13.8) from being notified by the Transmission Provider of a longer-term competing request for Short-Term Firm Point-To-Point Transmission Service. After the conditional reservation deadline, service will commence pursuant to the terms of Part II of the Tariff. Firm Point-To-Point Transmission Service will always have a reservation priority over Non-Firm Point-To-Point Transmission Service under the Tariff. All Long-Term Firm Point-To-Point Transmission Service will have equal reservation priority with Native Load Customers and Network Customers. Reservation priorities for existing firm service customers are provided in Section 2.2.
13.3 Use of Firm Transmission Service by the Transmission Provider: The Transmission Provider will be subject to the rates, terms and conditions of Part II of the Tariff when making Third-Party Sales under (i) agreements executed on or after July 9, 1996 or (ii) agreements executed prior to the aforementioned date that the Commission requires to be unbundled, by the date specified by the Commission. The Transmission Provider will maintain separate accounting, pursuant to Section 8, for any use of the Point-To-Point Transmission Service to make Third-Party Sales.
13.4 Service Agreements: The Transmission Provider shall offer a standard form Firm Point-To-Point Transmission Service Agreement (Attachment A) to an Eligible Customer when it submits a Completed Application for Long-Term Firm Point-To-Point Transmission Service. The Transmission Provider shall offer a standard form Firm Point-To-Point Transmission Service Agreement (Attachment A) to an Eligible Customer when it first submits a Completed Application for Short-Term Firm Point-To-Point Transmission Service pursuant to the Tariff. Executed Service Agreements that contain the information required under the Tariff shall be filed with the Commission in compliance with applicable Commission regulations.
13.5 Transmission Customer Obligations for Facility Additions or Redispatch Costs: In cases where the Transmission Provider determines that the Transmission System is not capable of providing Firm Point-To-Point Transmission Service without (1) degrading or impairing the reliability of service to Native Load Customers, Network Customers and other Transmission Customers taking Firm Point-To-Point Transmission Service, or (2) interfering with the Transmission Provider's ability to meet prior firm contractual commitments to others, the Transmission Provider will be obligated to expand or upgrade its Transmission System pursuant to the terms of Section 15.4. The Transmission Customer must agree to compensate the Transmission Provider for any necessary transmission facility additions pursuant to the terms of Section 27. To the extent the Transmission Provider can relieve any system constraint more economically by redispatching the Transmission Provider's resources than through constructing Network Upgrades, it shall do so, provided that the Eligible Customer agrees to compensate the Transmission Provider pursuant to the terms of Section 27. Any redispatch, Network Upgrade or Direct Assignment Facilities costs to be charged to the Transmission Customer on an incremental basis under the Tariff will be specified in the Service Agreement prior to initiating service.
13.6 Curtailment of Firm Transmission Service: In the event that a Curtailment on the Transmission Provider's Transmission System, or a portion thereof, is required to maintain reliable operation of such system, and the systems directly and indirectly interconnected with Transmission Provider’s Transmission System, Curtailments will be made on a non-discriminatory basis to the transaction(s) that effectively relieve the constraint. Transmission Provider may elect to implement such Curtailments pursuant to the Transmission Loading Relief procedures specified in Attachment O. If multiple transactions require Curtailment, to the extent practicable and consistent with Good Utility Practice, including actions taken to respond to directives given by the applicable NERC security coordinator, the Transmission Provider will curtail service to Network Customers and Transmission Customers taking Firm Point-To-Point Transmission Service on a basis comparable to the curtailment of service to the Transmission Provider's Native Load Customers. All Curtailments will be made on a non-discriminatory basis; however, Non-Firm Point-To-Point Transmission Service shall be subordinate to Firm Transmission Service. When the Transmission Provider determines that an electrical emergency exists on its Transmission System and implements emergency procedures to Curtail Firm Transmission Service, the Transmission Customer shall make the required reductions upon request of the Transmission Provider. However, the Transmission Provider reserves the right to Curtail, in whole or in part, any Firm Transmission Service provided under the Tariff when, in the Transmission Provider's sole discretion, an emergency or other unforeseen condition impairs or degrades the reliability of its Transmission System. The Transmission Provider will notify all affected Transmission Customers in a timely manner of any scheduled Curtailments. In the event the Transmission Customer fails to implement a Curtailment within ten minutes as directed by the Transmission Provider, the Transmission Customer shall pay, in addition to any other charges for service, a charge equal to the product of two times the amount of transmission service that the Transmission Customer fails to curtail and the maximum charge for Firm Point-To-Point Transmission Service for the lesser of the transaction term or one month.
13.7 Classification of Firm Transmission Service:
(a) The Transmission Customer taking Firm Point-To-Point Transmission Service may (1) change its Receipt and Delivery Points to obtain service on a non-firm basis consistent with the terms of Section 22.1 or (2) request a modification of the Points of Receipt or Delivery on a firm basis pursuant to the terms of Section 22.2.
(b) The Transmission Customer may purchase transmission service to make sales of capacity and energy from multiple generating units that are on the Transmission Provider's Transmission System. For such a purchase of transmission service, the resources will be designated as multiple Points of Receipt, unless the multiple generating units are at the same generating plant in which case the units would be treated as a single Point of Receipt.
(c) The Transmission Provider shall provide firm deliveries of capacity and energy from the Point(s) of Receipt to the Point(s) of Delivery. Each Point of Receipt at which firm transmission capacity is reserved by the Transmission Customer shall be set forth in the Firm Point-To-Point Service Agreement for Long-Term Firm Transmission Service along with a corresponding capacity reservation associated with each Point of Receipt. Points of Receipt and corresponding capacity reservations shall be as mutually agreed upon by the Parties for Short-Term Firm Transmission. Each Point of Delivery at which firm transmission capacity is reserved by the Transmission Customer shall be set forth in the Firm Point-To-Point Service Agreement for Long-Term Firm Transmission Service along with a corresponding capacity reservation associated with each Point of Delivery. Points of Delivery and corresponding capacity reservations shall be as mutually agreed upon by the Parties for Short-Term Firm Transmission. The greater of either (1) the sum of the capacity reservations at the Point(s) of Receipt, or (2) the sum of the capacity reservations at the Point(s) of Delivery shall be the Transmission Customer's Reserved Capacity. The Transmission Customer will be billed for its Reserved Capacity under the terms of Schedule 7. The Transmission Customer may not exceed its firm capacity reserved at each Point of Receipt and each Point of Delivery except as otherwise specified in Section 22. In the event that a Transmission Customer (including Third-Party Sales by the Transmission Provider) exceeds its firm reserved capacity at any Point of Receipt or Point of Delivery, the Transmission Customer shall pay, in addition to the otherwise applicable charge, a penalty equal to the product of two times the applicable charge and the amount of capacity used in excess of the Reserved Capacity for the lesser of the term of the transaction or one month.
13.8 Scheduling of Firm Point-To-Point Transmission Service: Schedules for the Transmission Customer's Firm Point-To-Point Transmission Service must comply with applicable NERC and Regional Reliability Council Policies, Transmission Customers shall submit all energy delivery schedules electronically in a form specified by the Transmission Provider. Schedules must be submitted to the Transmission Provider, and to the ERCOT ISO if the transaction involves the use of the CPL/WTU Transmission System., Schedules must be submitted no later than 10:00 a.m. of the day prior to commencement of such service (or at such other time corresponding to the scheduling deadline followed by an applicable regional transmission entity). Schedules submitted after 10:00 a.m. will be accommodated, if practicable. Hour-to-hour schedules of any capacity and energy that is to be delivered must be stated in increments of 1,000 kW per hour. Transmission Customers within the Transmission Provider's service area with multiple requests for Transmission Service at a Point of Receipt, each of which is under 1,000 kW per hour, may consolidate their service requests at a common point of receipt into units of 1,000 kW per hour for scheduling and billing purposes. Scheduling changes will be permitted up to twenty (20) minutes before the start of the next clock hour (or at such other time corresponding to the scheduling deadline followed by an applicable regional transmission entity) provided that the Delivering Party and Receiving Party also agree to the schedule modification. The Transmission Provider will furnish to the Delivering Party's system operator hour-to-hour schedules equal to those furnished by the Receiving Party (unless reduced for losses) and shall deliver the capacity and energy provided by such schedules. Should the Transmission Customer, Delivering Party or Receiving Party revise or terminate any schedule, such party shall immediately notify the Transmission Provider, and the Transmission Provider shall have the right to adjust accordingly the schedule for capacity and energy to be received and to be delivered.
13.9 Commonly Owned Facilities: Notwithstanding any other provision of this Section 13, Firm Point-To-Point Transmission Service provided pursuant to this Tariff shall not adversely affect the contractual or ownership rights of any entity that owns or operates, jointly with any of the AEP Operating Companies, any transmission facility or facilities included within the Transmission System.
14 Nature of Non-Firm Point-To-Point Transmission Service
14.1 Term: Non-Firm Point-To-Point Transmission Service will be available for periods ranging from one (1) hour to one (1) month. However, a Purchaser of Non-Firm Point-To-Point Transmission Service will be entitled to reserve a sequential term of service (such as a sequential monthly terms without having to wait for the initial term to expire before requesting another monthly term) so that the total time period for which the reservation applies is greater than one month, subject to the requirements of Section 18.3.
14.2 Reservation Priority: Non-Firm Point-To-Point Transmission Service shall be available from transmission capability in excess of that needed for reliable service to Native Load Customers, Network Customers and other Transmission Customers taking Long-Term and Short-Term Firm Point-To-Point Transmission Service. A higher priority will be assigned to reservations with a longer duration of service. In the event the Transmission System is constrained, competing requests of equal duration will be prioritized based on the highest price offered by the Eligible Customer for the Transmission Service. Eligible Customers that have already reserved shorter term service have the right of first refusal to match any longer term reservation before being preempted. A longer term competing request for Non-Firm Point-To-Point Transmission Service will be granted if the Eligible Customer with the right of first refusal does not agree to match the competing request: (a) immediately for hourly Non-Firm Point-To-Point Transmission Service after notification by the Transmission Provider; and, (b) within 24 hours (or earlier if necessary to comply with the scheduling deadlines provided in section 14.6) for Non-Firm Point-To-Point Transmission Service other than hourly transactions after notification by the Transmission Provider. Transmission service for Network Customers from resources other than designated Network Resources will have a higher priority than any Non-Firm Point-To-Point Transmission Service. Non-Firm Point-To-Point Transmission Service over secondary Point(s) of Receipt and Point(s) of Delivery will have the lowest reservation priority under the Tariff.
14.3 Use of Non-Firm Point-To-Point Transmission Service by the Transmission Provider: The Transmission Provider will be subject to the rates, terms and conditions of Part II of the Tariff when making Third-Party Sales under (i) agreements executed on or after July 9, 1996 or (ii) agreements executed prior to the aforementioned date that the Commission requires to be unbundled, by the date specified by the Commission. The Transmission Provider will maintain separate accounting, pursuant to Section 8, for any use of Non-Firm Point-To-Point Transmission Service to make Third-Party Sales.
14.4 Service Agreements: The Transmission Provider shall offer a standard form Non-Firm Point-To-Point Transmission Service Agreement (Attachment B) to an Eligible Customer when it first submits a Completed Application for Non-Firm Point-To-Point Transmission Service pursuant to the Tariff. Executed Service Agreements that contain the information required under the Tariff shall be filed with the Commission in compliance with applicable Commission regulations.
14.5 Classification of Non-Firm Point-To-Point Transmission Service: Non-Firm Point-To-Point Transmission Service shall be offered under terms and conditions contained in Part II of the Tariff. The Transmission Provider undertakes no obligation under the Tariff to plan its Transmission System in order to have sufficient capacity for Non-Firm Point-To-Point Transmission Service. Parties requesting Non-Firm Point-To-Point Transmission Service for the transmission of firm power do so with the full realization that such service is subject to availability and to Curtailment or Interruption under the terms of the Tariff. In the event that a Transmission Customer (including Third-Party Sales by the Transmission Provider) exceeds its non-firm capacity reservation at any Point of Receipt or Point of Delivery, the Transmission Customer shall pay, in addition to the otherwise applicable charge, a penalty equal to the product of two times the applicable charge and the amount of capacity used in excess of the Reserved Capacity for the lesser of the term of the transaction or one month. Non-Firm Point-To-Point Transmission Service shall include transmission of energy on an hourly basis and transmission of scheduled short-term capacity and energy on a daily, weekly or monthly basis, but not to exceed one year's reservation for any one Application, under Schedule 8.
14.6 Scheduling of Non-Firm Point-To-Point Transmission Service: Schedules for Non-Firm Point-To-Point Transmission Service must comply with applicable NERC and Regional Reliability Council Policies, Transmission Customers shall submit all energy delivery schedules electronically in a form specified by the Transmission Provider. Schedules must be submitted to the Transmission Provider, and to the ERCOT ISO if the transaction involves the use of the CPL/WTU Transmission System,. Schedules should be submitted no later than 2:00 p.m. of the day prior to commencement of such service (or at such other time corresponding to the scheduling deadline followed by an applicable regional transmission entity). Schedules submitted after 2:00 p.m. will be accommodated, if practicable. Hour-to-hour schedules of energy that is to be delivered must be stated in increments of 1,000 kW per hour. Transmission Customers within the Transmission Provider's service area with multiple requests for Transmission Service at a Point of Receipt, each of which is under 1,000 kW per hour, may consolidate their schedules at a common Point of Receipt into units of 1,000 kW per hour. Scheduling changes will be permitted up to twenty (20) minutes before the start of the next clock hour (or at such other time corresponding to the scheduling deadline followed by an applicable regional transmission entity) provided that the Delivering Party and Receiving Party also agree to the schedule modification. The Transmission Provider will furnish to the Delivering Party's system operator hour-to-hour schedules equal to those furnished by the Receiving Party (unless reduced for losses) and shall deliver the capacity and energy provided by such schedules. Should the Transmission Customer, Delivering Party or Receiving Party revise or terminate any schedule, such party shall immediately notify the Transmission Provider, and the Transmission Provider shall have the right to adjust accordingly the schedule for capacity and energy to be received and to be delivered.
14.7 Curtailment or Interruption of Service: The Transmission Provider reserves the right to Curtail, in whole or in part, Non-Firm Point-To-Point Transmission Service provided under the Tariff for reliability reasons when an emergency or other unforeseen condition threatens to impair or degrade the reliability of its Transmission System or the systems directly and indirectly interconnected with Transmission Provider’s Transmission System. Transmission Provider may elect to implement such Curtailments pursuant to the Transmission Loading Relief procedures specified in Attachment O. The Transmission Provider reserves the right to Interrupt, in whole or in part, Non-Firm Point-To-Point Transmission Service provided under the Tariff for economic reasons in order to accommodate (1) a request for Firm Transmission Service, (2) a request for Non-Firm Point-To-Point Transmission Service of greater duration, (3) a request for Non-Firm Point-To-Point Transmission Service of equal duration with a higher price, (4) transmission service for Network Customers from non-designated resources, or (5) directives given by the applicable NERC security coordinator. The Transmission Provider also will discontinue or reduce service to the Transmission Customer to the extent that deliveries for transmission are discontinued or reduced at the Point(s) of Receipt. Where required, Curtailments or Interruptions will be made on a non-discriminatory basis to the transaction(s) that effectively relieve the constraint, however, Non-Firm Point-To-Point Transmission Service shall be subordinate to Firm Transmission Service. If multiple transactions require Curtailment or Interruption, to the extent practicable and consistent with Good Utility Practice, Curtailments or Interruptions will be made to transactions of the shortest term (e.g., hourly non-firm transactions will be Curtailed or Interrupted before daily non-firm transactions and daily non-firm transactions will be Curtailed or Interrupted before weekly non-firm transactions). Transmission service for Network Customers from resources other than designated Network Resources will have a higher priority than any Non-Firm Point-To-Point Transmission Service under the Tariff. Non-Firm Point-To-Point Transmission Service over secondary Point(s) of Receipt and Point(s) of Delivery will have a lower priority than any Non-Firm Point-To-Point Transmission Service under the Tariff. The Transmission Provider will provide advance notice of Curtailment or Interruption where such notice can be provided consistent with Good Utility Practice. For purposes of implementing this Section 14.7, Planned Service provided under Part IV of this Tariff shall be deemed to be Firm Transmission Service and Unplanned Service provided under Part IV shall be deemed to be Non-Firm Transmission Service and, without limiting the generality of the term as applied to other sections of this Tariff, Good Utility Practice shall include determinations by the ERCOT ISO as to the reliability and operations of the ERCOT Transmission Network. In the event the Transmission Customer fails to implement a Curtailment within ten minutes or an Interruption within twenty (20) minutes after being so directed by the Transmission Provider (or at such other time corresponding to the scheduling deadline followed by an applicable regional transmission entity), the Transmission Customer shall pay, in addition to any other charges for service, a charge equal to the product of two times the amount of transmission service that the Transmission Customer fails to curtail and the maximum charge for Firm Point-to-Point Transmission Service for the lesser of the transaction term or one month.
14.8 Commonly Owned Facilities: Notwithstanding any other provision of this Section 14, Non-Firm Point-To-Point Transmission Service provided pursuant to this Tariff shall not adversely affect the contractual or ownership rights of any entity that owns or operates, jointly with any of the AEP Operating Companies, any transmission facility or facilities included within the Transmission System.
15 Service Availability
15.1 General Conditions: The Transmission Provider will provide Firm and Non-Firm Point-To-Point Transmission Service over, on or across its Transmission System to any Transmission Customer that has met the requirements of Section 16. A Transmission Customer taking service under Part IV of the Tariff may take Firm or Non-Firm Point-to-Point Transmission Service under this Part II of SPP Tariff to import power and energy Planned and Unplanned Rresources into ERCOT to serve ERCOT load.
15.2 Determination of Available Transmission Capability: A description of the Transmission Provider's specific methodology for assessing available transmission capability posted on the OASIS (Section 4) is contained in Attachment C of the Tariff. In the event sufficient transmission capability may not exist to accommodate a service request, the Transmission Provider will respond by performing a System Impact Study.
15.3 Initiating Service in the Absence of an Executed Service Agreement: If the Transmission Provider and the Transmission Customer requesting Firm or Non-Firm Point-To-Point Transmission Service cannot agree on all the terms and conditions of the Point-To-Point Service Agreement, the Transmission Provider shall file with the Commission, within thirty (30) days after the date the Transmission Customer provides written notification directing the Transmission Provider to file, an unexecuted Point-To-Point Service Agreement containing terms and conditions deemed appropriate by the Transmission Provider for such requested Transmission Service. The Transmission Provider shall commence providing Transmission Service subject to the Transmission Customer agreeing to (i) compensate the Transmission Provider at whatever rate the Commission ultimately determines to be just and reasonable, and (ii) comply with the terms and conditions of the Tariff including posting appropriate security deposits in accordance with the terms of Section 17.3.
15.4 Obligation to Provide Transmission Service that Requires Expansion or Modification of the Transmission System: If the Transmission Provider determines that it cannot accommodate a Completed Application for Firm Point-To-Point Transmission Service because of insufficient capability on its Transmission System, the Transmission Provider will use due diligence to expand or modify its Transmission System to provide the requested Firm Transmission Service, provided the Transmission Customer agrees to compensate the Transmission Provider for such costs pursuant to the terms of Section 27. The Transmission Provider will conform to Good Utility Practice in determining the need for new facilities and in the design and construction of such facilities. The obligation applies only to those facilities that the Transmission Provider has the right to expand or modify.
15.5 Deferral of Service: The Transmission Provider may defer providing service until it completes construction of new transmission facilities or upgrades needed to provide Firm Point-To-Point Transmission Service whenever the Transmission Provider determines that providing the requested service would, without such new facilities or upgrades, impair or degrade reliability to any existing firm services.
15.6 Other Transmission Service Schedules: Eligible Customers receiving transmission service under other agreements on file with the Commission may continue to receive transmission service under those agreements until such time as those agreements may be terminate or are otherwise modified by the Commission.
15.7 Real Power Losses: Real Power Losses are associated with all transmission service. The Transmission Provider is not obligated to provide Real Power Losses, but the Transmission Customer may purchase capacity and energy necessary to compensate for losses from the Transmission Provider pursuant to Schedule 20, Loss Compensation Service. The Transmission Customer is responsible for replacing losses associated with all transmission service provided under Part II as calculated by the Transmission Provider. The applicable Real Power Loss factors are as follows:
For transmission to a Point of Delivery in the AEP East Zone, the loss factor is 3.3%. For transmission to a Point of Delivery in the AEP West Zone, the loss factor is 2.9%; provided, however, that for transactions that involve the transmission of energy generated in ERCOT to a load located in ERCOT, the Transmission Customer's shall provide energy to cover losses in according with the ERCOT Protocols.loss responsibility shall be the lesser of 2.9% or the losses for which CPL and WTU are due compensation under Chapter 25 of the PUCT's Substantive Rules. A Lload Sserving Eentity that takes ERCOT Regional Transmission Service under Part IV of this Tariff and also takes Transmission Service under Part II of this Tariff or under the SPP Tariff to import energy into ERCOT to serve its Native Lload cCustomers in ERCOT shall provide for energy to cover losses in according with the ERCOT Protocols, be liable to CPL and WTU for losses under Chapter 25 of the PUCT's Substantive Rules and shall be otherwise required, pursuant to this Tariff, to provide Real Power Losses to the Transmission System at a capacity loss factor of 1.5% if service is taken under Part II of this Tariff, or and under the loss compensation provision of the SPP Tariff., if service is taken under that SPP Tariff.
A Transmission Customer that takes service under Part II of this Tariff in conjunction with the terms of the SPP Tariff to transmit energy from a Point of Receipt located in ERCOT to a Point of Delivery located outside of ERCOT shall be responsible for providing losses according to the ERCOT Protocols, and for compensating the SPP for losses under the SPP Tariff. liable to the Transmission Provider for losses determined by reference to matrices prepared by the ERCOT ISO for exports of energy from ERCOT under Chapter 25 of the PUCT Substantive Rules and shall otherwise be required to compensate PSO and SWEPCO for real power losses under the SPP Tariff.
16 Transmission Customer Responsibilities
16.1 Conditions Required of Transmission Customers: Point-To-Point Transmission Service shall be provided by the Transmission Provider only if the following conditions are satisfied by the Transmission Customer:
a. The Transmission Customer has pending a Completed Application for service;
b. The Transmission Customer meets the creditworthiness criteria set forth in Section 11;
c. Prior to the time service under Part II of the Tariff commences, the Transmission Customer will have arrangements in place for any other transmission service necessary to effect the delivery from the generating source to the Transmission Provider and to effect the delivery from the Transmission Provider to the Transmission Customer or the ultimate wholesale purchaser from the Transmission Customer (including without limitation any transmission service needed from a third party to transfer energy between the AEP East Zone and the AEP West Zone);
d. The Transmission Customer agrees to pay for any facilities constructed and chargeable to such Transmission Customer under Part II of the Tariff, whether or not the Transmission Customer takes service for the full term of its reservation; and
e. The Transmission Customer has executed a Point-To-Point Service Agreement or has agreed to receive service pursuant to Section 15.3.
16.2 Transmission Customer Responsibility for Third-Party Arrangements: Any scheduling arrangements that may be required by other electric systems shall be the responsibility of the Transmission Customer requesting service. The Transmission Customer shall provide, unless waived by the Transmission Provider, notification to the Transmission Provider identifying such systems and authorizing them to schedule the capacity and energy to be transmitted by the Transmission Provider pursuant to Part II of the Tariff on behalf of the Receiving Party at the Point of Delivery or the Delivering Party at the Point of Receipt. However, the Transmission Provider will undertake reasonable efforts to assist the Transmission Customer in making such arrangements, including without limitation, providing any information or data required by such other electric system pursuant to Good Utility Practice. A Transmission Customer shall coordinate its use of the HVDC Facilities with the ERCOT ISO and the SPP security coordinator and the Transmission Customer shall be liable for any administrative or other charge imposed by the ERCOT ISO or the SPP security coordinator.
17 Procedures for Arranging Firm Point-To-Point Transmission Service
17.1 Application: A request for Firm Point-To-Point Transmission Service for periods of one year or longer must contain a written Application to:
American Electric Power Service Corporation
Attn: Director, Transmission and Interconnection Services
1 Riverside Plaza
Columbus, Ohio 43215-2373
at least sixty (60) days in advance of the calendar month in which service is to commence. The Transmission Provider will consider requests for such firm service on shorter notice when feasible. Requests for firm service for periods of less than one year shall be subject to expedited procedures that shall be negotiated between the Parties within the time constraints provided in Section 17.5. All Firm Point-To-Point Transmission Service requests should be submitted by entering the information listed below on the OASIS. In the event the OASIS is not in operation, a Completed Application may be submitted by (i) transmitting the required information to the Transmission Provider by telefax, or (ii) providing the information via overnight delivery. Submission by telefax will provide a time-stamped record for establishing the priority of the Application.
17.2 Completed Application: A Completed Application shall provide all of the information included in 18 C.F.R. § 2.20 including but not limited to the following:
(i) The identity, address, telephone number and facsimile number of the entity requesting service;
(ii) A statement that the entity requesting service is, or will be upon commencement of service, an Eligible Customer under the Tariff;
(iii) The location of the Point(s) of Receipt and Point(s) of Delivery and the identities of the Delivering Parties and the Receiving Parties;
(iv) The location of the generating facility(ies) supplying the capacity and energy and the location of the load ultimately served by the capacity and energy transmitted. The Transmission Provider will treat this information as confidential except to the extent that disclosure of this information is required by this Tariff, by regulatory or judicial order, for reliability purposes pursuant to Good Utility Practice or pursuant to RTG transmission information sharing agreements. The Transmission Provider shall treat this information consistent with the standards of conduct contained in Part 37 of the Commission's regulations;
(v) A description of the supply characteristics of the capacity and energy to be delivered;
(vi) An estimate of the capacity and energy expected to be delivered to the Receiving Party;
(vii) The Service Commencement Date and the term of the requested Transmission Service;
(viii) The transmission capacity requested for each Point of Receipt and each Point of Delivery on the Transmission Provider's Transmission System; customers may combine their requests for service in order to satisfy the minimum transmission capacity requirement. The Transmission Provider shall treat this information consistent with the standards of conduct contained in Part 37 of the Commission's regulations;
(ix) The Eligible Customer's NERC registered DUNS number as displayed on ; and
(x) The identity and contact number of the Eligible Customer's accounts payable personnel.
17.3 Deposit: A Completed Application for Firm Point-To-Point Transmission Service also shall include a deposit of either one month's charge for Reserved Capacity or the full charge for Reserved Capacity for service requests of less than one month. If the Application is rejected by the Transmission Provider because it does not meet the conditions for service as set forth herein, or in the case of requests for service arising in connection with losing bidders in a Request For Proposals (RFP), said deposit shall be returned with interest less any reasonable costs incurred by the Transmission Provider in connection with the review of the losing bidder's Application. The deposit also will be returned with interest less any reasonable costs incurred by the Transmission Provider if the Transmission Provider is unable to complete new facilities needed to provide the service. If an Application is withdrawn or the Eligible Customer decides not to enter into a Service Agreement for Firm Point-To-Point Transmission Service, the deposit shall be refunded in full, with interest, less reasonable costs incurred by the Transmission Provider to the extent such costs have not already been recovered by the Transmission Provider from the Eligible Customer. The Transmission Provider will provide to the Eligible Customer a complete accounting of all costs deducted from the refunded deposit, which the Eligible Customer may contest if there is a dispute concerning the deducted costs. Deposits associated with construction of new facilities are subject to the provisions of Section 19. If a Service Agreement for Firm Point-To-Point Transmission Service is executed, the deposit, with interest, will be returned to the Transmission Customer upon expiration or termination of the Service Agreement for Firm Point-To-Point Transmission Service. Applicable interest shall be computed in accordance with the Commission's regulations at 18 C.F.R. § 35.19a(a)(2)(iii), and shall be calculated from the day the deposit check is credited to the Transmission Provider's account.
Notwithstanding the foregoing, the Transmission Provider may, on a non-discriminatory basis, waive the requirement that a deposit accompany an Application where the Eligible Customer has established its creditworthiness pursuant to Section 11 of this Tariff and is not in default in its obligations under this Tariff, as defined in Section 7.3 of this Tariff, at the time of the Application.
17.4 Notice of Deficient Application: If an Application fails to meet the requirements of the Tariff, the Transmission Provider shall notify the entity requesting service within fifteen (15) days of receipt of the reasons for such failure. The Transmission Provider will attempt to remedy minor deficiencies in the Application through informal communications with the Eligible Customer. If such efforts are unsuccessful, the Transmission Provider shall return the Application, along with any deposit, with interest. Upon receipt of a new or revised Application that fully complies with the requirements of Part II of the Tariff, the Eligible Customer shall be assigned a new priority consistent with the date of the new or revised Application.
17.5 Response to a Completed Application: Following receipt of a Completed Application for Firm Point-To-Point Transmission Service, the Transmission Provider shall make a determination of available transmission capability as required in Section 15.2. The Transmission Provider shall notify the Eligible Customer as soon as practicable, but not later than thirty (30) days after the date of receipt of a Completed Application either (i) if it will be able to provide service without performing a System Impact Study or (ii) if such a study is needed to evaluate the impact of the Application pursuant to Section 19.1. Responses by the Transmission Provider must be made as soon as practicable to all completed applications (including applications by its own merchant function) and the timing of such responses must be made on a non-discriminatory basis.
17.6 Execution of Service Agreement: Whenever the Transmission Provider determines that a System Impact Study is not required and that the service can be provided, it shall notify the Eligible Customer as soon as practicable but no later than thirty (30) days after receipt of the Completed Application. Where a System Impact Study is required, the provisions of Section 19 will govern the execution of a Service Agreement. Failure of an Eligible Customer to execute and return the Service Agreement or request the filing of an unexecuted service agreement pursuant to Section 15.3, within fifteen (15) days after it is tendered by the Transmission Provider will be deemed a withdrawal and termination of the Application and any deposit submitted shall be refunded with interest. Nothing herein limits the right of an Eligible Customer to file another Application after such withdrawal and termination.
17.7 Extensions for Commencement of Service: The Transmission Customer can obtain up to five (5) one-year extensions for the commencement of service. The Transmission Customer may postpone service by paying a non-refundable annual reservation fee equal to one-month's charge for Firm Transmission Service for each year or fraction thereof. If during any extension for the commencement of service an Eligible Customer submits a Completed Application for Firm Transmission Service, and such request can be satisfied only by releasing all or part of the Transmission Customer's Reserved Capacity, the original Reserved Capacity will be released unless the following condition is satisfied. Within thirty (30) days, the original Transmission Customer agrees to pay the Firm Point-To-Point transmission rate for its Reserved Capacity concurrent with the new Service Commencement Date. In the event the Transmission Customer elects to release the Reserved Capacity, the reservation fees or portions thereof previously paid will be forfeited.
18 Procedures for Arranging Non-Firm Point-To-Point Transmission Service
18.1 Application: Eligible Customers seeking Non-Firm Point-To-Point Transmission Service must submit a Completed Application to the Transmission Provider. Applications should be submitted by entering the information listed below on the OASIS. In the event the OASIS is not in operation, a Completed Application may be submitted by (i) transmitting the required information by telefax, or (ii) providing the information via overnight delivery to:
American Electric Power Service Corporation
Attn: Director, Transmission and Interconnection Services
1 Riverside Plaza
Columbus, Ohio 43215-2373
Submission by telefax will provide a time-stamped record for establishing the service priority of the Application.
18.2 Completed Application: A Completed Application shall provide all of the information included in 18 C.F.R. § 2.20 including but not limited to the following:
(i) The identity, address, telephone number and facsimile number of the entity requesting service;
(ii) A statement that the entity requesting service is, or will be upon commencement of service, an Eligible Customer under the Tariff;
(iii) The Point(s) of Receipt and the Point(s) of Delivery;
(iv) The maximum amount of capacity requested at each Point of Receipt and Point of Delivery;
(v) The proposed dates and hours for initiating and terminating transmission service hereunder;
(vi) The Eligible Customer's NERC registered DUNS number as displayed on ; and
(vii) The identity and contact number of the Eligible Customer's accounts payable personnel.
In addition to the information specified above, when required to properly evaluate system conditions the Transmission Provider also may ask the Transmission Customer to provide the following:
(viii) The electrical location of the initial source of the power to be transmitted pursuant to the Transmission Customer's request for service; and
(ix) The electrical location of the ultimate load.
The Transmission Provider will treat this information in (viii) and (ix) as confidential at the request of the Transmission Customer except to the extent that disclosure of this information is required by this Tariff, by regulatory or judicial order, for reliability purposes pursuant to Good Utility Practice, or pursuant to RTG transmission information sharing agreements. The Transmission Provider shall treat this information consistent with the standards of conduct contained in Part 37 of the Commission's regulations.
18.3 Reservation of Non-Firm Point-To-Point Transmission Service: Requests for monthly service for one month or up to twelve consecutive months shall be submitted no earlier than sixty (60) days before service is to commence; requests for weekly service shall be submitted no earlier than fourteen (14) days before service is to commence, requests for daily service shall be submitted no earlier than two (2) days before service is to commence, and requests for hourly service shall be submitted no earlier than noon the day before service is to commence. Requests for service received later than 2:00 p.m. (or at such other time corresponding to the scheduling deadline followed by an applicable regional transmission entity) prior to the day service is scheduled to commence will be accommodated if practicable.
18.4 Determination of Available Transmission Capability: Following receipt of a tendered schedule the Transmission Provider will make a determination on a non-discriminatory basis of available transmission capability pursuant to Section 15.2. Such determination shall be made as soon as reasonably practicable after receipt, but not later than the following time periods for the following terms of service (i) thirty (30) minutes for hourly service, (ii) thirty (30) minutes for daily service, (iii) four (4) hours for weekly service, and (iv) two (2) days for monthly service(or at such other time corresponding to the scheduling deadline followed by an applicable regional transmission entity).
19 Additional Study Procedures For Firm Point-To-Point Transmission Service Requests
19.1 Notice of Need for System Impact Study: After receiving a request for service, the Transmission Provider shall determine on a non-discriminatory basis whether a System Impact Study is needed. A description of the Transmission Provider's methodology for completing a System Impact Study is provided in Attachment D. If the Transmission Provider determines that a System Impact Study is necessary to accommodate the requested service, it shall so inform the Eligible Customer, as soon as practicable. In such cases, the Transmission Provider shall within thirty (30) days of receipt of a Completed Application, tender a System Impact Study Agreement pursuant to which the Eligible Customer shall agree to reimburse the Transmission Provider for performing the required System Impact Study. For a service request to remain a Completed Application, the Eligible Customer shall execute the System Impact Study Agreement and return it to the Transmission Provider within fifteen (15) days. If the Eligible Customer elects not to execute the System Impact Study Agreement, its application shall be deemed withdrawn and its deposit, pursuant to Section 17.3, shall be returned with interest.
19.2 System Impact Study Agreement and Cost Reimbursement:
(i) The System Impact Study Agreement will clearly specify the Transmission Provider's estimate of the actual cost, and time for completion of the System Impact Study. The charge shall not exceed the actual cost of the study. In performing the System Impact Study, the Transmission Provider shall rely, to the extent reasonably practicable, on existing transmission planning studies. The Eligible Customer will not be assessed a charge for such existing studies; however, the Eligible Customer will be responsible for charges associated with any modifications to existing planning studies that are reasonably necessary to evaluate the impact of the Eligible Customer's request for service on the Transmission System.
(ii) If in response to multiple Eligible Customers requesting service in relation to the same competitive solicitation, a single System Impact Study is sufficient for the Transmission Provider to accommodate the requests for service, the costs of that study shall be pro-rated among the Eligible Customers.
(iii) For System Impact Studies that the Transmission Provider conducts on its own behalf, the Transmission Provider shall record the cost of the System Impact Studies pursuant to Section 20.
19.3 System Impact Study Procedures: Upon receipt of an executed System Impact Study Agreement, the Transmission Provider will use due diligence to complete the required System Impact Study within a sixty (60) day period. The System Impact Study shall identify any system constraints and redispatch options, additional Direct Assignment Facilities or Network Upgrades required to provide the requested service. In the event that the Transmission Provider is unable to complete the required System Impact Study within such time period, it shall so notify the Eligible Customer and provide an estimated completion date along with an explanation of the reasons why additional time is required to complete the required studies. A copy of the completed System Impact Study and related work papers shall be made available to the Eligible Customer. The Transmission Provider will use the same due diligence in completing the System Impact Study for an Eligible Customer as it uses when completing studies for itself. The Transmission Provider shall notify the Eligible Customer immediately upon completion of the System Impact Study if the Transmission System will be adequate to accommodate all or part of a request for service or that no costs are likely to be incurred for new transmission facilities or upgrades. In order for a request to remain a Completed Application, within fifteen (15) days of completion of the System Impact Study the Eligible Customer must execute a Service Agreement or request the filing of an unexecuted Service Agreement pursuant to Section 15.3, or the Application shall be deemed terminated and withdrawn.
19.4 Facilities Study Procedures: If a System Impact Study indicates that additions or upgrades to the Transmission System are needed to supply the Eligible Customer's service request, the Transmission Provider, within thirty (30) days of the completion of the System Impact Study, shall tender to the Eligible Customer a Facilities Study Agreement pursuant to which the Eligible Customer shall agree to reimburse the Transmission Provider for performing the required Facilities Study. For a service request to remain a Completed Application, the Eligible Customer shall execute the Facilities Study Agreement and return it to the Transmission Provider within fifteen (15) days. If the Eligible Customer elects not to execute the Facilities Study Agreement, its application shall be deemed withdrawn and its deposit, pursuant to Section 17.3, shall be returned with interest. Upon receipt of an executed Facilities Study Agreement, the Transmission Provider will use due diligence to complete the required Facilities Study within a sixty (60) day period. If the Transmission Provider is unable to complete the Facilities Study in the allotted time period, the Transmission Provider shall notify the Transmission Customer and provide an estimate of the time needed to reach a final determination along with an explanation of the reasons that additional time is required to complete the study. When completed, the Facilities Study will include a good faith estimate of (i) the cost of Direct Assignment Facilities to be charged to the Transmission Customer, (ii) the Transmission Customer's appropriate share of the cost of any required Network Upgrades as determined pursuant to the provisions of Part II of the Tariff, and (iii) the time required to complete such construction and initiate the requested service. The Transmission Customer shall provide the Transmission Provider with a letter of credit or other reasonable form of security acceptable to the Transmission Provider equivalent to the costs of new facilities or upgrades consistent with commercial practices as established by the Uniform Commercial Code. The Transmission Customer shall have thirty (30) days to execute a Service Agreement or request the filing of an unexecuted Service Agreement and provide the required letter of credit or other form of security or the request will no longer be a Completed Application and shall be deemed terminated and withdrawn.
19.5 Facilities Study Modifications: Any change in design arising from inability to site or construct facilities as proposed will require development of a revised good faith estimate. New good faith estimates also will be required in the event of new statutory or regulatory requirements that are effective before the completion of construction or other circumstances beyond the control of the Transmission Provider that significantly affect the final cost of new facilities or upgrades to be charged to the Transmission Customer pursuant to the provisions of Part II of the Tariff.
19.6 Due Diligence in Completing New Facilities: The Transmission Provider shall use due diligence to add necessary facilities or upgrade its Transmission System within a reasonable time. The Transmission Provider will not upgrade its existing or planned Transmission System in order to provide the requested Firm Point-To-Point Transmission Service if doing so would impair system reliability or otherwise impair or degrade existing firm service.
19.7 Partial Interim Service: If the Transmission Provider determines that it will not have adequate transmission capability to satisfy the full amount of a Completed Application for Firm Point-To-Point Transmission Service, the Transmission Provider nonetheless shall be obligated to offer and provide the portion of the requested Firm Point-To-Point Transmission Service that can be accommodated without addition of any facilities and through redispatch. However, the Transmission Provider shall not be obligated to provide the incremental amount of requested Firm Point-To-Point Transmission Service that requires the addition of facilities or upgrades to the Transmission System until such facilities or upgrades have been placed in service.
19.8 Expedited Procedures for New Facilities: In lieu of the procedures set forth above, the Eligible Customer shall have the option to expedite the process by requesting the Transmission Provider to tender at one time, together with the results of required studies, an "Expedited Service Agreement" pursuant to which the Eligible Customer would agree to compensate the Transmission Provider for all costs incurred pursuant to the terms of the Tariff. In order to exercise this option, the Eligible Customer shall request in writing an expedited Service Agreement covering all of the above-specified items within thirty (30) days of receiving the results of the System Impact Study identifying needed facility additions or upgrades or costs incurred in providing the requested service. While the Transmission Provider agrees to provide the Eligible Customer with its best estimate of the new facility costs and other charges that may be incurred, such estimate shall not be binding and the Eligible Customer must agree in writing to compensate the Transmission Provider for all costs incurred pursuant to the provisions of the Tariff. The Eligible Customer shall execute and return such an Expedited Service Agreement within fifteen (15) days of its receipt or the Eligible Customer's request for service will cease to be a Completed Application and will be deemed terminated and withdrawn.
20 Procedures if The Transmission Provider is Unable to Complete New Transmission Facilities for Firm Point-To-Point Transmission Service
20.1 Delays in Construction of New Facilities: If any event occurs that will materially affect the time for completion of new facilities, or the ability to complete them, the Transmission Provider shall promptly notify the Transmission Customer. In such circumstances, the Transmission Provider shall within thirty (30) days of notifying the Transmission Customer of such delays, convene a technical meeting with the Transmission Customer to evaluate the alternatives available to the Transmission Customer. The Transmission Provider also shall make available to the Transmission Customer studies and work papers related to the delay, including all information that is in the possession of the Transmission Provider that is reasonably needed by the Transmission Customer to evaluate any alternatives.
20.2 Alternatives to the Original Facility Additions: When the review process of Section 20.1 determines that one or more alternatives exist to the originally planned construction project, the Transmission Provider shall present such alternatives for consideration by the Transmission Customer. If, upon review of any alternatives, the Transmission Customer desires to maintain its Completed Application subject to construction of the alternative facilities, it may request the Transmission Provider to submit a revised Service Agreement for Firm Point-To-Point Transmission Service. If the alternative approach solely involves Non-Firm Point-To-Point Transmission Service, the Transmission Provider shall promptly tender a Service Agreement for Non-Firm Point- To-Point Transmission Service providing for the service. In the event the Transmission Provider concludes that no reasonable alternative exists and the Transmission Customer disagrees, the Transmission Customer may seek relief under the dispute resolution procedures pursuant to Section 12 or it may refer the dispute to the Commission for resolution.
20.3 Refund Obligation for Unfinished Facility Additions: If the Transmission Provider and the Transmission Customer mutually agree that no other reasonable alternatives exist and the requested service cannot be provided out of existing capability under the conditions of Part II of the Tariff, the obligation to provide the requested Firm Point-To- Point Transmission Service shall terminate and any deposit made by the Transmission Customer shall be returned with interest pursuant to Commission regulations 35.19a(a)(2)(iii). However, the Transmission Customer shall be responsible for all prudently incurred costs by the Transmission Provider through the time construction was suspended.
21 Provisions Relating to Transmission Construction and Services on the Systems of Other Utilities
21.1 Responsibility for Third-Party System Additions: The Transmission Provider shall not be responsible for making arrangements for any necessary engineering, permitting, and construction of transmission or distribution facilities on the system(s) of any other entity or for obtaining any regulatory approval for such facilities. The Transmission Provider will undertake reasonable efforts to assist the Transmission Customer in obtaining such arrangements, including without limitation, providing any information or data required by such other electric system pursuant to Good Utility Practice.
21.2 Coordination of Third-Party System Additions: In circumstances where the need for transmission facilities or upgrades is identified pursuant to the provisions of Part II of the Tariff, and if such upgrades further require the addition of transmission facilities on other systems, the Transmission Provider shall have the right to coordinate construction on its own system with the construction required by others. The Transmission Provider, after consultation with the Transmission Customer and representatives of such other systems, may defer construction of its new transmission facilities, if the new transmission facilities on another system cannot be completed in a timely manner. The Transmission Provider shall notify the Transmission Customer in writing of the basis for any decision to defer construction and the specific problems which must be resolved before it will initiate or resume construction of new facilities. Within sixty (60) days of receiving written notification by the Transmission Provider of its intent to defer construction pursuant to this section, the Transmission Customer may challenge the decision in accordance with the dispute resolution procedures pursuant to Section 12 or it may refer the dispute to the Commission for resolution.
22 Changes in Service Specifications
22.1 Modifications On a Non-Firm Basis: The Transmission Customer taking Firm Point-To-Point Transmission Service may request the Transmission Provider to provide transmission service on a non-firm basis over Receipt and Delivery Points other than those specified in the Service Agreement ("Secondary Receipt and Delivery Points"), in amounts not to exceed its firm capacity reservation, without incurring an additional Non-Firm Point-To-Point Transmission Service charge or executing a new Service Agreement, subject to the following conditions.
(a) Service provided over Secondary Receipt and Delivery Points will be non-firm only, on an as-available basis and will not displace any firm or non-firm service reserved or scheduled by third-parties under the Tariff or by the Transmission Provider on behalf of its Native Load Customers and the rate applicable to such service shall be based on the Zone in which the delivery point is located.
(b) The sum of all Firm and Non-firm Point-To-Point Transmission Service provided to the Transmission Customer at any time pursuant to this section shall not exceed the Reserved Capacity in the relevant Service Agreement under which such services are provided.
(c) The Transmission Customer shall retain its right to schedule Firm Point-To-Point Transmission Service at the Receipt and Delivery Points specified in the relevant Service Agreement in the amount of its original capacity reservation.
(d) Service over Secondary Receipt and Delivery Points on a non-firm basis shall not require the filing of an Application for Non-Firm Point-To-Point Transmission Service under the Tariff. However, all other requirements of Part II of the Tariff (except as to transmission rates) shall apply to transmission service on a non-firm basis over Secondary Receipt and Delivery Points.
22.2 Modification On a Firm Basis: Any request by a Transmission Customer to modify Receipt and Delivery Points on a firm basis shall be treated as a new request for service in accordance with Section 17 hereof, except that such Transmission Customer shall not be obligated to pay any additional deposit if the capacity reservation does not exceed the amount reserved in the existing Service Agreement. While such new request is pending, the Transmission Customer shall retain its priority for service at the existing firm Receipt and Delivery Points specified in its Service Agreement.
23 Sale or Assignment of Transmission Service
23.1 Procedures for Assignment or Transfer of Service: Subject to Commission approval of any necessary filings, a Transmission Customer may sell, assign, or transfer all or a portion of its rights under its Service Agreement, but only to another Eligible Customer (the Assignee). The Transmission Customer that sells, assigns or transfers its rights under its Service Agreement is hereafter referred to as the Reseller. Compensation to the Reseller shall not exceed the higher of (i) the original rate paid by the Reseller, (ii) the Transmission Provider's maximum rate on file at the time of the assignment, or (iii) the Reseller's opportunity cost capped at the Transmission Provider's cost of expansion. If the Assignee does not request any change in the Point(s) of Receipt or the Point(s) of Delivery, or a change in any other term or condition set forth in the original Service Agreement, the Assignee will receive the same services as did the Reseller and the priority of service for the Assignee will be the same as that of the Reseller. A Reseller should notify the Transmission Provider as soon as possible after any assignment or transfer of service occurs but in any event, notification must be provided prior to any provision of service to the Assignee. The Assignee will be subject to all terms and conditions of this Tariff. If the Assignee requests a change in service, the reservation priority of service will be determined by the Transmission Provider pursuant to Section 13.2.
23.2 Limitations on Assignment or Transfer of Service: If the Assignee requests a change in the Point(s) of Receipt or Point(s) of Delivery, or a change in any other specifications set forth in the original Service Agreement, the Transmission Provider will consent to such change subject to the provisions of the Tariff, provided that the change will not impair the operation and reliability of the Transmission Provider's generation, transmission, or distribution systems. The Assignee shall compensate the Transmission Provider for performing any System Impact Study needed to evaluate the capability of the Transmission System to accommodate the proposed change and any additional costs resulting from such change. The Reseller shall remain liable for the performance of all obligations under the Service Agreement, except as specifically agreed to by the Parties through an amendment to the Service Agreement.
23.3 Information on Assignment or Transfer of Service: In accordance with Section 4, Resellers may use the OASIS to post transmission capacity available for resale.
24 Metering and Power Factor Correction at Receipt and Delivery Points(s)
24.1 Transmission Customer Obligations: Unless otherwise agreed, the Transmission Customer shall be responsible for installing and maintaining compatible meteri37ng and communications equipment to accurately account for the capacity and energy being transmitted under Part II of the Tariff and to communicate the information to the Transmission Provider. Such equipment shall remain the property of the Transmission Customer. The Transmission Customer shall inspect its metering equipment for accuracy in registration at least biennially and at its own expense. The Transmission Customer shall also perform meter tests at the request of the Transmission Provider within normal business hours. If any metering equipment test shows the Transmission Customer's metering equipment not to be accurate within +/- 2%, the Transmission Customer shall replace such equipment with accurate equipment or restore the existing equipment to accurate registration at the Transmission Customer's own expense. If a metering test requested by the Transmission Provider shows the Transmission Customer's equipment to be registering accurately within +/- 2%, the Transmission Provider shall pay the costs of such test.
24.2 Transmission Provider Access to Metering Data: The Transmission Provider shall have access to metering data, which may reasonably be required to facilitate measurements and billing under the Service Agreement.
24.3 Power Factor: Unless otherwise agreed, the Transmission Customer is required to maintain a power factor within the same range as the Transmission Provider pursuant to Good Utility Practices. The power factor requirements are specified in the Service Agreement where applicable.
25 Compensation for Transmission Service
Rates for Firm and Non-Firm Point-To-Point Transmission Service are provided in the Schedules appended to the Tariff: Firm Point-To-Point Transmission Service (Schedule 7); and Non-Firm Point-To-Point Transmission Service (Schedule 8). The Transmission Provider shall use Part II of the Tariff to make its Third-Party Sales. The Transmission Provider shall account for such use at the applicable Tariff rates, pursuant to Section 8.
26 Stranded Cost Recovery
The Transmission Provider may seek to recover stranded costs from the Transmission Customer pursuant to this Tariff in accordance with the terms, conditions and procedures set forth in FERC Order No. 888. However, the Transmission Provider must separately file any specific proposed stranded cost charge under Section 205 of the Federal Power Act.
27 Compensation for New Facilities and Redispatch Costs
Whenever a System Impact Study performed by the Transmission Provider in connection with the provision of Firm Point-To-Point Transmission Service identifies the need for new facilities, the Transmission Customer shall be responsible for such costs to the extent consistent with Commission policy. Whenever a System Impact Study performed by the Transmission Provider identifies capacity constraints that may be relieved more economically by redispatching the Transmission Provider's resources than by building new facilities or upgrading existing facilities to eliminate such constraints, the Transmission Customer shall be responsible for the redispatch costs to the extent consistent with Commission policy and Chapter 25.
III. NETWORK INTEGRATION TRANSMISSION SERVICE
Preamble
The Transmission Provider offers Network Integration Transmission Service pursuant to the applicable terms and conditions set forth in this Tariff, the Transmission Customer’s Network Integration Transmission Service Agreement, and the Transmission Customer’s Network Service Operating Agreement. Network Integration Transmission Service allows the Network Customer to integrate, economically dispatch and regulate its current and planned Network Resources to serve its Network Loads in a manner comparable to that in which the Transmission Provider utilizes its Transmission System to serve its Native Load Customers. Network Integration Transmission Service also may be used by the Network Customer to deliver energy to its Network Load from resources not designated as Network Resources on an as-available basis without additional charge. Transmission service for sales by the Transmission Customer to loads not designated as Network Loads will be provided in accordance with the applicable terms and conditions of Part II of the Tariff.
Network Integration Transmission Service used to serve Network Load located in the SPP, or that otherwise makes use of that portion of the Transmission System located in the SPP, other than Network Integration Transmission Service that is grandfathered under Sections 1.14a and 37.4 of the SPP Tariff, shall be taken under the SPP Tariff in accordance with the applicable terms and conditions of the SPP Tariff.
Charges for Network Integration Transmission Service under this Tariff, if applicable, are based on whether the Transmission Customer’s Network Load is located in the AEP East Zone or the AEP West Zone. To accomplish the delivery of energy from Network Resources to Network Load, the Transmission Customer may also be required to arrange and pay for service under the transmission tariffs of other transmission providers, including without limitation the SPP Tariff.
Delivery to Network Load in the East Zone
7 A Network Customer that takes Network Integration Transmission Service to serve Network Load located in or served from the AEP East Zone shall be liable to the Transmission Provider for the Network Customer’s Load Ratio Share of the AEP East Zone annual transmission revenue requirement set forth in Attachment H to the Tariff, regardless of the location of the Network Customer’s Network Resources on the Transmission System.
Delivery to Network Load in the AEP West Zone for Transactions that are Grandfathered Under the SPP Tariff
2. Any Network Integration Transmission Service to Network Load located in or served from the SPP subject to a service agreement executed before February 1, 2000, shall continue to be taken exclusively under the rates, terms and conditions of this Tariff relating to Network Integration Transmission Service. Network Customers that are party to such grandfathered agreements shall remain liable to the Transmission Provider for the Network Customer’s Load Ratio Share of the applicable AEP West Zone annual transmission revenue requirement set forth in Attachment H to the Tariff.
Delivery to Network Load in the West Zone for Transactions that are Not Grandfathered Under the SPP Tariff
Into the SPP From the AEP East Zone
3. A Network Customer that takes Network Integration Transmission Service under the SPP Tariff to serve Network Load located in or served from the AEP West Zone portion of the SPP from Network Resources located in the AEP East Zone shall not be liable to the Transmission Provider for Network Integration Transmission Service or Point-to-Point Transmission Service charges under this Tariff.
Into ERCOT from the AEP East Zone or the SPP
4. A Network Customer that takes Network Integration Transmission Service to serve its Network Load located in ERCOT from Network Resources scheduled into the Transmission System in the Eastern Interconnection shall be liable to the Transmission Provider for charges under Parts III and IV of the Tariff.
Into SPP from ERCOT
5. A Network Customer that takes Network Integration Transmission Service under the SPP Tariff to serve Network Load from Network Resources located in ERCOT shall be liable to the Transmission Provider for Point-to-Point Transmission Service under Part II of this Tariff.
Within the SPP Only
6. A Network Customer that takes Network Integration Transmission Service under the SPP Tariff to serve Network Load located in the SPP from Network Resources located outside of the AEP East Zone or ERCOT shall not be subject to any charges under this Tariff.
28 Nature of Network Integration Transmission Service
28.1 Scope of Service: Network Integration Transmission Service is a transmission service that allows Network Customers to efficiently and economically utilize their Network Resources (as well as other non-designated generation resources) to serve their Network Load located in any of the Transmission Provider's Control Areas and any additional load that may be designated pursuant to Section 31.3 of the Tariff. The Network Customer taking Network Integration Transmission Service must obtain or provide Ancillary Services pursuant to Section 3.
28.2 Transmission Provider Responsibilities: The Transmission Provider will plan, construct, operate and maintain its Transmission System in accordance with Good Utility Practice in order to provide the Network Customer with Network Integration Transmission Service over the Transmission Provider's Transmission System. The Transmission Provider, on behalf of its Native Load Customers, shall be required to designate resources and loads in the same manner as any Network Customer under Part III of this Tariff. This information must be consistent with the information used by the Transmission Provider to calculate available transmission capability. The Transmission Provider shall include the Network Customer's Network Load in its Transmission System planning and shall, consistent with Good Utility Practice, endeavor to construct and place into service sufficient transmission capacity to deliver the Network Customer's Network Resources to serve its Network Load on a basis comparable to the Transmission Provider's delivery of its own generating and purchased resources to its Native Load Customers.
28.3 Network Integration Transmission Service: The Transmission Provider will provide firm transmission service over its Transmission System to the Network Customer for the delivery of capacity and energy from its designated Network Resources to service its Network Loads on a basis that is comparable to the Transmission Provider's use of the Transmission System to reliably serve its Native Load Customers.
28.4 Secondary Service: The Network Customer may use the Transmission Provider's Transmission System to deliver energy to its Network Loads from resources that have not been designated as Network Resources. Such energy shall be transmitted, on an as-available basis, at no additional charge. Deliveries from resources other than Network Resources will have a higher priority than any Non-Firm Point-To-Point Transmission Service under Part II of the Tariff.
28.5 Real Power Losses: Real Power Losses are associated with all transmission service. The Transmission Provider is not obligated to provide Real Power Losses, but the Transmission Customer may purchase capacity and energy necessary to compensate for losses from the Transmission Provider pursuant to Schedule 20, Loss Compensation Service. The Network Customer is responsible for replacing losses associated with all transmission service as calculated by the Transmission Provider. The applicable Real Power Loss factors are as follows:
For transmission to a point of delivery in the AEP East Zone, the loss factor is 3.3%. For transmission to a point of delivery in the AEP West Zone, the loss factor is 2.9%. A Transmission Customer that compensates Load Serving Entity that takes service under Part III of this Tariff shall not be liable to CPL and WTU for losses under Chapter 25 of the PUCT Substantive Rules.the ERCOT Protocols shall not be liable for losses under Part III of the Tariff.
28.6 Restrictions on Use of Service: The Network Customer shall not use Network Integration Transmission Service for (i) sales of capacity and energy to non-designated loads, or (ii) direct or indirect provision of transmission service by the Network Customer to third parties. All Network Customers taking Network Integration Transmission Service shall use Point-To-Point Transmission Service under Part II of the Tariff for any Third-Party Sale which requires use of the Transmission Provider's Transmission System.
29 Initiating Service
29.1 Condition Precedent for Receiving Service: Subject to the terms and conditions of Part III of the Tariff, the Transmission Provider will provide Network Integration Transmission Service to any Eligible Customer, provided that (i) the Eligible Customer completes an Application for service as provided under Part III of the Tariff, (ii) the Eligible Customer and the Transmission Provider complete the technical arrangements set forth in Sections 29.3 and 29.4, (iii) the Eligible Customer executes a Service Agreement pursuant to Attachment F for service under Part III of the Tariff or requests in writing that the Transmission Provider file a proposed unexecuted Service Agreement with the Commission, and (iv) the Eligible Customer executes a Network Operating Agreement with the Transmission Provider pursuant to Attachment G, or requests in writing that the Transmission Provider file a proposed unexecuted Network Operating Agreement.
29.2 Application Procedures: An Eligible Customer requesting service under Part III of the Tariff must submit an Application, with a deposit approximating the charge for one month of service, to the Transmission Provider as far as possible in advance of the month in which service is to commence. Unless subject to the procedures in Section 2, Completed Applications for Network Integration Transmission Service will be assigned a priority according to the date and time the Application is received, with the earliest Application receiving the highest priority. Applications should be submitted by entering the information listed below on the OASIS. In the event the OASIS is not in operation, a Completed Application may be submitted by (i) transmitting the required information to the Transmission Provider by telefax, or (ii) providing the information by via overnight delivery to:
American Electric Power Service Corporation
Attn: Director, Transmission and Interconnection Services
1 Riverside Plaza
Columbus, Ohio 43215-2373
Submission by telefax will provide a time-stamped record for establishing the service priority of the Application. A Completed Application shall provide all of the information included in 18 C.F.R. § 2.20 including but not limited to the following:
(i) The identity, address, telephone number and facsimile number of the party requesting service;
(ii) A statement that the party requesting service is, or will be upon commencement of service, an Eligible Customer under the Tariff;
(iii) A description of the Network Load at each delivery point. This description should separately identify and provide the Eligible Customer's best estimate of the total loads to be served at each transmission voltage level, and the loads to be served from each Transmission Provider substation at the same transmission voltage level. The description should include a ten (10) year forecast of summer and winter load and resource requirements beginning with the first year after the service is scheduled to commence;
(iv) The amount and location of any interruptible loads included in the Network Load. This shall include the summer and winter capacity requirements for each interruptible load (had such load not been interruptible), that portion of the load subject to interruption, the conditions under which an interruption can be implemented and any limitations on the amount and frequency of interruptions. An Eligible Customer should identify the amount of interruptible customer load (if any) included in the 10-year load forecast provided in response to (iii) above;
(v) A description of Network Resources (current and 10-year projection), which shall include, for each Network Resource:
- Unit size and amount of capacity from that unit to be designated as Network Resource
- VAR capability (both leading and lagging) of all generators
- Operating restrictions
- Any periods of restricted operations throughout the year
- Maintenance schedules
- Minimum loading level of unit
- Normal operating level of unit
- Any must-run unit designations required for system reliability or contract reasons
- Approximate variable generating cost ($/MWH) for redispatch computations
- Arrangements governing sale and delivery of power to third parties from generating facilities located in the Transmission Provider Control Area, where only a portion of unit output is designated as a Network Resource
- Description of purchased power designated as a Network Resource including source of supply, Control Area location, transmission arrangements and delivery point(s) to the Transmission Provider's Transmission System;
(vi) Description of Eligible Customer's transmission system:
- Load flow and stability data, such as real and reactive parts of the load, lines, transformers, reactive devices and load type, including normal and emergency ratings of all transmission equipment in a load flow format compatible with that used by the Transmission Provider
- Operating restrictions needed for reliability
- Operating guides employed by system operators
- Contractual restrictions or committed uses of the Eligible Customer's transmission system, other than the Eligible Customer's Network Loads and Resources
- Location of Network Resources described in subsection (v) above
- 10 year projection of system expansions or upgrades
- Transmission System maps that include any proposed expansions or upgrades
- Thermal ratings of Eligible Customer's Control Area ties with other Control Areas; and
(vii) Service Commencement Date and the term of the requested Network Integration Transmission Service. The minimum term for Network Integration Transmission Service is one year.
Unless the Parties agree to a different time frame, the Transmission Provider must acknowledge the request within ten (10) days of receipt. The acknowledgement must include a date by which a response, including a Service Agreement, will be sent to the Eligible Customer. If an Application fails to meet the requirements of this section, the Transmission Provider shall notify the Eligible Customer requesting service within fifteen (15) days of receipt and specify the reasons for such failure. Wherever possible, the Transmission Provider will attempt to remedy deficiencies in the Application through informal communications with the Eligible Customer. If such efforts are unsuccessful, the Transmission Provider shall return the Application without prejudice to the Eligible Customer filing a new or revised Application that fully complies with the requirements of this section. The Eligible Customer will be assigned a new priority consistent with the date of the new or revised Application. The Transmission Provider shall treat this information consistent with the standards of conduct contained in Part 37 of the Commission's regulations. The Transmission Provider may, on a non-discriminatory basis, waive the requirement that a deposit accompany an Application for Network Integration Transmission Service where the Eligible Customer has established its creditworthiness pursuant to Section 11 of the Tariff and is not in default of its obligations under this Tariff, as defined in Section 7.3 of the Tariff, at the time of the Application.
29.3 Technical Arrangements to be Completed Prior to Commencement of Service: Network Integration Transmission Service shall not commence until the Transmission Provider and the Network Customer, or a third party, have completed installation of all equipment specified under the Network Operating Agreement consistent with Good Utility Practice and any additional requirements reasonably and consistently imposed to ensure the reliable operation of the Transmission System. The Transmission Provider shall exercise reasonable efforts, in coordination with the Network Customer, to complete such arrangements as soon as practicable taking into consideration the Service Commencement Date.
29.4 Network Customer Facilities: The provision of Network Integration Transmission Service shall be conditioned upon the Network Customer's constructing, maintaining and operating the facilities on its side of each delivery point or interconnection necessary to reliably deliver capacity and energy from the Transmission Provider's Transmission System to the Network Customer. The Network Customer shall be solely responsible for constructing or installing all facilities on the Network Customer's side of each such delivery point or interconnection.
29.5 Filing of Service Agreement: The Transmission Provider will file Service Agreements with the Commission in compliance with applicable Commission regulations.
30 Network Resources
30.1 Designation of Network Resources: Network Resources shall include all generation owned, purchased or leased by the Network Customer designated to serve Network Load under the Tariff. Network Resources may not include resources, or any portion thereof, that are committed for sale to non-designated third party load or otherwise cannot be called upon to meet the Network Customer's Network Load on a non-interruptible basis. Any owned or purchased resources that were serving the Network Customer's loads under firm agreements entered into on or before the Service Commencement Date shall initially be designated as Network Resources until the Network Customer terminates the designation of such resources.
30.2 Designation of New Network Resources: The Network Customer may designate a new Network Resource by providing the Transmission Provider with as much advance notice as practicable. A designation of a new Network Resource must be made by a request for modification of service pursuant to an Application under Section 29.
30.3 Termination of Network Resources: The Network Customer may terminate the designation of all or part of a generating resource as a Network Resource at any time but should provide notification to the Transmission Provider as soon as reasonably practicable.
30.4 Operation of Network Resources: The Network Customer shall not operate its designated Network Resources located in the Network Customer's or Transmission Provider's Control Areas such that the output of those facilities exceeds its designated Network Load, plus non-firm sales delivered pursuant to this Tariff or the SPP Tariff, plus losses. This limitation shall not apply to changes in the operation of a Transmission Customer's Network Resources at the request of the Transmission Provider to respond to an emergency or other unforeseen condition which may impair or degrade the reliability of the Transmission System.
30.5 Network Customer Redispatch Obligation: As a condition to receiving Network Integration Transmission Service, the Network Customer agrees to redispatch its Network Resources as requested by the Transmission Provider pursuant to Section 33.2. To the extent practical, the redispatch of resources pursuant to this section shall be on a least cost, non-discriminatory basis between all Network Customers, and the Transmission Provider.
30.6 Transmission Arrangements for Network Resources Not Physically Interconnected With The Transmission Provider: The Network Customer shall be responsible for any arrangements necessary to deliver capacity and energy from a Network Resource not physically interconnected with the Transmission Provider's Transmission System. The Transmission Provider will undertake reasonable efforts to assist the Network Customer in obtaining such arrangements, including without limitation, providing any information or data required by such other entity pursuant to Good Utility Practice.
30.7 Limitation on Designation of Network Resources: The Network Customer must demonstrate that it owns or has committed to purchase generation pursuant to an executed contract in order to designate a generating resource as a Network Resource. Alternatively, the Network Customer may establish that execution of a contract is contingent upon the availability of transmission service under Part III of the Tariff.
30.8 Use of Interface Capacity by the Network Customer: There is no limitation upon a Network Customer's use of the Transmission Provider's Transmission System at any particular interface to integrate the Network Customer's Network Resources (or substitute economy purchases) with its Network Loads. However, a Network Customer's use of the Transmission Provider's total interface capacity with other transmission systems may not exceed the Network Customer's Load. A Transmission Customer shall coordinate its use of the HVDC Facilities with the ERCOT ISO and the SPP security coordinator and the Transmission Customer shall be liable for any administrative or other charge imposed by the ERCOT ISO or the SPP security coordinator.
30.9 Network Customer Owned Transmission Facilities: The Network Customer that owns existing transmission facilities that are integrated with the Transmission Provider's Transmission System may be eligible to receive consideration either through a billing credit or some other mechanism. In order to receive such consideration the Network Customer must demonstrate that its transmission facilities are integrated into the plans or operations of the Transmission Provider to serve its power and transmission customers. For facilities constructed by the Network Customer subsequent to the Service Commencement Date under Part III of the Tariff, the Network Customer shall receive credit where such facilities are jointly planned and installed in coordination with the Transmission Provider. Calculation of the credit shall be addressed in either the Network Customer's Service Agreement or any other agreement between the Parties.
31 Designation of Network Load
31.1 Network Load: The Network Customer must designate the individual Network Loads on whose behalf the Transmission Provider will provide Network Integration Transmission Service. The Network Loads shall be specified in the Service Agreement.
31.2 New Network Loads Connected With the Transmission Provider: The Network Customer shall provide the Transmission Provider with as much advance notice as reasonably practicable of the designation of new Network Load that will be added to its Transmission System. A designation of new Network Load must be made through a modification of service pursuant to a new Application. The Transmission Provider will use due diligence to install any transmission facilities required to interconnect a new Network Load designated by the Network Customer. The costs of new facilities required to interconnect a new Network Load shall be determined in accordance with the procedures provided in Section 32.4 and shall be charged to the Network Customer in accordance with Commission policies.
31.3 Network Load Not Physically Interconnected with the Transmission Provider: This section applies to both initial designation pursuant to Section 31.1 and the subsequent addition of new Network Load not physically interconnected with the Transmission Provider. To the extent that the Network Customer desires to obtain transmission service for a load outside the Transmission Provider's Transmission System, the Network Customer shall have the option of (1) electing to include the entire load as Network Load for all purposes under Part III of the Tariff and designating Network Resources in connection with such additional Network Load, or (2) excluding that entire load from its Network Load and purchasing Point-To-Point Transmission Service under Part II of the Tariff. To the extent that the Network Customer gives notice of its intent to add a new Network Load as part of its Network Load pursuant to this section the request must be made through a modification of service pursuant to a new Application.
31.4 New Interconnection Points: To the extent the Network Customer desires to add a new Delivery Point or interconnection point between the Transmission Provider's Transmission System and a Network Load, the Network Customer shall provide the Transmission Provider with as much advance notice as reasonably practicable.
31.5 Changes in Service Requests: Under no circumstances shall the Network Customer's decision to cancel or delay a requested change in Network Integration Transmission Service (e.g. the addition of a new Network Resource or designation of a new Network Load) in any way relieve the Network Customer of its obligation to pay the costs of transmission facilities constructed by the Transmission Provider and charged to the Network Customer as reflected in the Service Agreement. However, the Transmission Provider must treat any requested change in Network Integration Transmission Service in a non-discriminatory manner.
31.6 Annual Load and Resource Information Updates: The Network Customer shall provide the Transmission Provider with annual updates of Network Load and Network Resource forecasts consistent with those included in its Application for Network Integration Transmission Service under Part III of the Tariff. The Network Customer also shall provide the Transmission Provider with timely written notice of material changes in any other information provided in its Application relating to the Network Customer's Network Load, Network Resources, its transmission system or other aspects of its facilities or operations affecting the Transmission Provider's ability to provide reliable service.
32 Additional Study Procedures For Network Integration Transmission Service Requests
32.1 Notice of Need for System Impact Study: After receiving a request for service, the Transmission Provider shall determine on a non-discriminatory basis whether a System Impact Study is needed. A description of the Transmission Provider's methodology for completing a System Impact Study is provided in Attachment D. If the Transmission Provider determines that a System Impact Study is necessary to accommodate the requested service, it shall so inform the Eligible Customer, as soon as practicable. In such cases, the Transmission Provider shall within thirty (30) days of receipt of a Completed Application, tender a System Impact Study Agreement pursuant to which the Eligible Customer shall agree to reimburse the Transmission Provider for performing the required System Impact Study. For a service request to remain a Completed Application, the Eligible Customer shall execute the System Impact Study Agreement and return it to the Transmission Provider within fifteen (15) days. If the Eligible Customer elects not to execute the System Impact Study Agreement, its Application shall be deemed withdrawn and its deposit shall be returned with interest.
32.2 System Impact Study Agreement and Cost Reimbursement:
(i) The System Impact Study Agreement will clearly specify the Transmission Provider's estimate of the actual cost, and time for completion of the System Impact Study. The charge shall not exceed the actual cost of the study. In performing the System Impact Study, the Transmission Provider shall rely, to the extent reasonably practicable, on existing transmission planning studies. The Eligible Customer will not be assessed a charge for such existing studies; however, the Eligible Customer will be responsible for charges associated with any modifications to existing planning studies that are reasonably necessary to evaluate the impact of the Eligible Customer's request for service on the Transmission System.
(ii) If in response to multiple Eligible Customers requesting service in relation to the same competitive solicitation, a single System Impact Study is sufficient for the Transmission Provider to accommodate the service requests, the costs of that study shall be pro-rated among the Eligible Customers.
(iii) For System Impact Studies that the Transmission Provider conducts on its own behalf, the Transmission Provider shall record the cost of the System Impact Studies pursuant to Section 8.
32.3 System Impact Study Procedures: Upon receipt of an executed System Impact Study Agreement, the Transmission Provider will use due diligence to complete the required System Impact Study within a sixty (60) day period. The System Impact Study shall identify any system constraints and redispatch options, additional Direct Assignment Facilities or Network Upgrades required to provide the requested service. In the event that the Transmission Provider is unable to complete the required System Impact Study within such time period, it shall so notify the Eligible Customer and provide an estimated completion date along with an explanation of the reasons why additional time is required to complete the required studies. A copy of the completed System Impact Study and related work papers shall be made available to the Eligible Customer. The Transmission Provider will use the same due diligence in completing the System Impact Study for an Eligible Customer as it uses when completing studies for itself. The Transmission Provider shall notify the Eligible Customer immediately upon completion of the System Impact Study if the Transmission System will be adequate to accommodate all or part of a request for service or that no costs are likely to be incurred for new transmission facilities or upgrades. In order for a request to remain a Completed Application, within fifteen (15) days of completion of the System Impact Study the Eligible Customer must execute a Service Agreement or request the filing of an unexecuted Service Agreement, or the Application shall be deemed terminated and withdrawn.
32.4 Facilities Study Procedures: If a System Impact Study indicates that additions or upgrades to the Transmission System are needed to supply the Eligible Customer's service request, the Transmission Provider, within thirty (30) days of the completion of the System Impact Study, shall tender to the Eligible Customer a Facilities Study Agreement pursuant to which the Eligible Customer shall agree to reimburse the Transmission Provider for performing the required Facilities Study. For a service request to remain a Completed Application, the Eligible Customer shall execute the Facilities Study Agreement and return it to the Transmission Provider within fifteen (15) days. If the Eligible Customer elects not to execute the Facilities Study Agreement, its Application shall be deemed withdrawn and its deposit shall be returned with interest. Upon receipt of an executed Facilities Study Agreement, the Transmission Provider will use due diligence to complete the required Facilities Study within a sixty (60) day period. If the Transmission Provider is unable to complete the Facilities Study in the allotted time period, the Transmission Provider shall notify the Eligible Customer and provide an estimate of the time needed to reach a final determination along with an explanation of the reasons that additional time is required to complete the study. When completed, the Facilities Study will include a good faith estimate of (i) the cost of Direct Assignment Facilities to be charged to the Eligible Customer, (ii) the Eligible Customer's appropriate share of the cost of any required Network Upgrades, and (iii) the time required to complete such construction and initiate the requested service. The Eligible Customer shall provide the Transmission Provider with a letter of credit or other reasonable form of security acceptable to the Transmission Provider equivalent to the costs of new facilities or upgrades consistent with commercial practices as established by the Uniform Commercial Code. The Eligible Customer shall have thirty (30) days to execute a Service Agreement or request the filing of an unexecuted Service Agreement and provide the required letter of credit or other form of security or the request no longer will be a Completed Application and shall be deemed terminated and withdrawn.
33 Load Shedding and Curtailments
33.1 Procedures: Prior to the Service Commencement Date, the Transmission Provider and the Network Customer shall establish Load Shedding and Curtailment procedures pursuant to the Network Operating Agreement with the objective of responding to contingencies on the Transmission System and on systems directly and indirectly interconnected with Transmission Provider’s Transmission System. The Parties will implement such programs during any period when the Transmission Provider determines that a system contingency exists and such procedures are necessary to alleviate such contingency. The Transmission Provider will notify all affected Network Customers in a timely manner of any scheduled Curtailment.
33.2 Transmission Constraints: During any period when the Transmission Provider determines that a transmission constraint exists on the Transmission System, and such constraint may impair the reliability of the Transmission Provider's system, the Transmission Provider will take whatever actions, consistent with Good Utility Practice, that are reasonably necessary to maintain the reliability of the Transmission Provider's system. To the extent the Transmission Provider determines that the reliability of the Transmission System can be maintained by redispatching resources, the Transmission Provider will initiate procedures pursuant to the Network Operating Agreement to redispatch all Network Resources and the Transmission Provider's own resources on a least-cost basis without regard to the ownership of such resources. Any redispatch under this section may not unduly discriminate between the Transmission Provider's use of the Transmission System on behalf of its Native Load Customers and any Network Customer's use of the Transmission System to serve its designated Network Load.
33.3 Cost Responsibility for Relieving Transmission Constraints: Except to the extent otherwise provided in Chapter 25 of the PUCT’s Substantive Rules whenever the Transmission Provider implements least-cost redispatch procedures in response to a transmission constraint, the Transmission Provider and Network Customers will each bear a proportionate share of the total redispatch cost based on their respective Load Ratio Shares.
33.4 Curtailments of Scheduled Deliveries: If a transmission constraint on the Transmission Provider's Transmission System cannot be relieved through the implementation of least-cost redispatch procedures and the Transmission Provider determines that it is necessary to Curtail scheduled deliveries, the Parties shall Curtail such schedules in accordance with the Network Operating Agreement or pursuant to the Transmission Loading Relief procedures specified in Attachment O.
33.5 Allocation of Curtailments: The Transmission Provider shall, on a non-discriminatory basis, Curtail the transaction(s) that effectively relieve the constraint. However, to the extent practicable and consistent with Good Utility Practice, including actions taken to respond to directives given by the applicable NERC security coordinator, any Curtailment will be shared by the Transmission Provider and Network Customer in proportion to their respective Load Ratio Shares. The Transmission Provider shall not direct the Network Customer to Curtail schedules to an extent greater than the Transmission Provider would Curtail the Transmission Provider's schedules under similar circumstances.
33.6 Load Shedding: To the extent that a system contingency exists on the Transmission Provider's Transmission System and the Transmission Provider determines that it is necessary for the Transmission Provider and the Network Customer to shed load, the Parties shall shed load in accordance with previously established procedures under the Network Operating Agreement.
33.7 System Reliability: Notwithstanding any other provisions of this Tariff, the Transmission Provider reserves the right, consistent with Good Utility Practice and on a not unduly discriminatory basis, to Curtail Network Integration Transmission Service without liability on the Transmission Provider's part for the purpose of making necessary adjustments to, changes in, or repairs on its lines, substations and facilities, and in cases where the continuance of Network Integration Transmission Service would endanger persons or property. In the event of any adverse condition(s) or disturbance(s) on the Transmission Provider's Transmission System or on any other system(s) directly or indirectly interconnected with the Transmission Provider's Transmission System, the Transmission Provider, consistent with Good Utility Practice, also may Curtail Network Integration Transmission Service in order to (i) limit the extent or damage of the adverse condition(s) or disturbance(s), (ii) prevent damage to generating or transmission facilities, (iii) expedite restoration of service, or (iv) as otherwise directed by the applicable NERC security coordinator. The Transmission Provider will give the Network Customer as much advance notice as is practicable in the event of such Curtailment. Any Curtailment of Network Integration Transmission Service will be not unduly discriminatory relative to the Transmission Provider's use of the Transmission System on behalf of its Native Load Customers. In the event the Network Customer fails to respond to established Load Shedding and Curtailment procedures, the Network Customer shall pay, in addition to any other charges for service, a charge equal to two times the amount of transmission service the Network Customer fails to curtail times the monthly charge for Network Integration Transmission Service.
34 Rates and Charges
The Network Customer shall pay the Transmission Provider for any Direct Assignment Facilities, Ancillary Services, and applicable study costs, consistent with Commission policy, along with the following:
34.1 Monthly Demand Charge: The Network Customer shall pay a monthly Demand Charge, which shall be determined in accordance with Attachment H. If the Network Customer is a Load Serving Entity, takes service under both Part III and Part IV, the Network Customer shall pay its Load Ratio Share as determined by the preceding sentence and pay to CPL and WTU a monthly demand charge for Planned Sservice (determined before netting) pursuant to Part IV and Attachment K, of this Tariff.
34.2 Determination of Network Customer's Monthly Network Load: The Network Customer's monthly Network Load is its hourly load (including its designated Network Load not physically interconnected with the Transmission Provider under Section 31.3) coincident with the Transmission Provider's Monthly Transmission System Peak in that part of the Transmission System (the AEP East Zone or the AEP West Zone) in which such Network Load is located or from which energy to be transmitted to the Control Area in which Network Load not physically interconnected to the Transmission System is delivered.
(a) Contract Demand Network Service: Generally, the net output of any generating capacity operated by the Network Customer behind the meter(s) for any Delivery Point(s), at the time of the Transmission Provider's Monthly Transmission System Peak Load, will be added to the load measured at the Delivery Point, in order to determine the Network Customer's Network Load. The foregoing notwithstanding, a Network Customer that operates generation as part of an electric utility system interconnected with the Transmission System in the AEP East Zone for the purpose of serving the requirements of retail electric consumers connected to its distribution lines may elect to have the Network Load at any Delivery Point(s) located in the AEP East Zone based on a Contract Demand Reservation (CDR) accepted by the Transmission Provider, rather than the total of behind-the-meter generation and Delivery Point load.
(b) Terms for East Zone Contract Demand Network Service: If an East Zone Network Customer eligible under 34.2 (a) above elects to use Contract Demand Network Service, the following shall apply:
(i) The minimum Term of Contract Demand Network Service shall be three years. The initial Term of Service Agreements invoking these provisions shall not extend beyond December 31, 2006, provided;, however, that if the Transmission Provider places its Transmission System (or part thereof serving such network customer) and its provision of Transmission Service under the authority of a Regional Transmission Operator (RTO), (1) the Transmission Customer may terminate the Service Agreement upon not less than twelve (12) months written notice from the date the Transmission Provider provides notice of intent to place its facilities in the AEP East Zone under the authority of an RTO in order for the Transmission Customer to request service under the RTO Tariff, and (2) if the RTO uses a zonal pricing plan, at least for some period of transition, the Transmission Customer shall be permitted to extend service under this special provision at least until the end of such transition period (expected to permit such service until April 30, 2007).
(ii) The Network Customer shall specify in the Application for service which Delivery Point(s) are to be billed pursuant to a CDR, and the CDR amount(s) requested for each year of the Term of Service. The CDR for any such Delivery Point(s) shall not be less than the projected load at such point(s) at the time of the Transmission System Peak Load less the amount of behind-the-meter generation reasonably expected to be available at such time. The Transmission Customer shall explain the basis for any year-to-year variation in the CDR requested for any Delivery Point(s).
(iii) Two or more Delivery Points may be combined under one CDR; however, the Transmission Customer shall designate an allocation of such CDR to the individual Delivery Points.
(iv) During the Term of Service, the Transmission Provider shall not be obligated to plan the Transmission System nor to curtail any other firm transmission service in order to deliver more than the CDR amount of power to any Delivery Point on a firm basis than the Transmission Customer has specified in its CDR or Delivery Point allocation of a combined CDR. This provision applies only to the Delivery Point(s) covered by CDR(s), and does not affect the Transmission Customer's or the Transmission Provider's rights or obligations with regards to system planning or curtailment at other Delivery Points.
(v) The Transmission Customer may make a change in the Delivery Point(s) that are to be billed pursuant to a CDR and/or make a change in the CDR for any Delivery Point(s) for the second or subsequent years of the Term of Service, provided that the Transmission Customer gives notice of such change at least ninety (90) days prior to the date such change would be effective, and provided further that any decrease in the CDR for any Delivery Point(s) shall not exceed 30% of the existing CDR in any year.
(vi) The Transmission Provider shall accept the initial and subsequent CDRs and CDR changes provided by the Transmission Customer, unless it determines that the Transmission System lacks the capacity to accommodate such change.
(vii) The Transmission Customer may request firm or non-firm Point-to-Point Transmission Service under Part II of the Tariff to deliver power to any Delivery Point(s) in excess of the CDR, subject to the availability and terms of such service.
(viii) For billing purposes and calculation of the Customer's Load Ratio Share, the Customer's Network Load will be the sum of its CDR and the Network Load measured at Delivery Points not reserved pursuant to these special provisions
(ix) If the Transmission Provider determines that Transmission Service must be curtailed at any Delivery Point(s) covered by a CDR, it shall notify the Transmission Customer of such curtailment consistent with the provisions of the Tariff. If the Transmission Customer does not fully comply with such request within ten (10) minutes of the Transmission Provider's Notice (or such other notice period or generator startup period specified in the Service Agreement if longer), then, for billing purposes, the CDR will be increased for that Billing Period to the lowest demand level achieved at such Delivery Point(s) during such Notice (or Startup) period, and thereafter until the Transmission Customer has demonstrated that the generation at such point(s) can be made to operate at a level that would support a lower CDR, or for twelve (12) months, whichever is greater.
(x) Except as otherwise provided in this subsection 32.4 (b) 34.2(a) and 32.4 (a)34.2(b), all the provisions of the Tariff, including, without limitation, those relating to redispatch of Network Resources and Curtailments of Transmission Service, shall apply.
34.3 Determination of Transmission Provider's Monthly Transmission System Load: The Transmission Provider's monthly Transmission System load, determined separately for the East and the West zZones, is the Transmission Provider's Monthly Transmission System Peak minus the coincident peak usage of all Firm Point-To-Point Transmission Service customers pursuant to Part II of this Tariff plus the Reserved Capacity of all Firm Point-To-Point Transmission Service customers.
34.4 Redispatch Charge: Except to the extent otherwise provided in Chapter 25 or the ERCOT Protocols, the Network Customer shall pay a Load Ratio Share of any redispatch costs allocated between the Network Customer and the Transmission Provider pursuant to Section 33. To the extent that the Transmission Provider incurs an obligation to the Network Customer for redispatch costs in accordance with Section 33, such amounts shall be credited against the Network Customer's bill for the applicable month.
34.5 Stranded Cost Recovery: The Transmission Provider may seek to recover stranded costs from the Network Customer pursuant to this Tariff in accordance with the terms, conditions and procedures set forth in FERC Order No. 888. However, the Transmission Provider must separately file any proposal to recover stranded costs under Section 205 of the Federal Power Act.
35 Operating Arrangements
35.1 Operation under The Network Operating Agreement: The Network Customer shall plan, construct, operate and maintain its facilities in accordance with Good Utility Practice and in conformance with the Network Operating Agreement.
35.2 Network Operating Agreement: The terms and conditions under which the Network Customer shall operate its facilities and the technical and operational matters associated with the implementation of Part III of the Tariff shall be specified in the Network Operating Agreement. The Network Operating Agreement shall provide for the Parties to (i) operate and maintain equipment necessary for integrating the Network Customer within the Transmission Provider's Transmission System (including, but not limited to, remote terminal units, metering, communications equipment and relaying equipment), (ii) transfer data between the Transmission Provider and the Network Customer (including, but not limited to, heat rates and operational characteristics of Network Resources, generation schedules for units outside the Transmission Provider's Transmission System, interchange schedules (which shall be submitted electronically in a form specified by the Transmission Provider), unit outputs for redispatch required under Section 33, voltage schedules, loss factors and other real time data), (iii) use software programs required for data links and constraint dispatching, (iv) exchange data on forecasted loads and resources necessary for long-term planning; and (v) address any other technical and operational considerations required for implementation of Part III of the Tariff, including scheduling protocols.
The Network Operating Agreement will recognize that the Network Customer shall either (i) operate as a Control Area under applicable guidelines of the North American Electric Reliability Council (NERC) and the applicable regional reliability council, (ii) satisfy its Control Area requirements, including all necessary Ancillary Services, by contracting with the Transmission Provider, or (iii) satisfy its Control Area requirements, including all necessary Ancillary Services, by contracting with another entity, consistent with Good Utility Practice, which satisfies NERC and the applicable regional reliability council requirements. The Transmission Provider shall not unreasonably refuse to accept contractual arrangements with another entity for Ancillary Services. The Network Operating Agreement is included in Attachment G.
35.3 Network Operating Committee: A Network Operating Committee (Committee) shall be established to coordinate operating criteria for the Parties' respective responsibilities under the Network Operating Agreement. Each Network Customer shall be entitled to have at least one representative on the Committee. The Committee shall meet from time to time as need requires, but no less than once each calendar year.
IV ERCOT REGIONAL TRANSMISSION SERVICE
Preamble
CPL and WTU will participate in the provision of ERCOT Regional Transmission Service in accordance with ERCOT Protocols and the terms and conditions set forth in this Part IV and a Transmission Customer's Service Agreement. Chapter 25 sets forth the principles by which the responsibility for the costs of owning, operating, maintaining and expanding the ERCOT Transmission Network will be distributed among all electric utility Load Serving Eentities operating in ERCOT. In the event of any conflict between this Tariff and Chapter 25 or ERCOT Protocols, or any future modification of the PUCT’s Substantive Rules or ERCOT Protocols, the provisions of this Tariff will control.
36 ERCOT Regional Transmission Service
36.1 Purpose: This Part IV sets forth the terms and conditions that shall govern the participation by CPL and WTU in assuring non-discriminatory access to use of the ERCOT Transmission Network required to serve loads in ERCOT. Planned Service Transmission service provided pursuant to this Part IV together with like service provided by other Transmission Providers in accordance with Chapter 25 allows an Eligible Customer Load Serving Entity operating in ERCOT to receive energy from its Planned resources to serve loads within ERCOT. and to receive energy associated with Unplanned Resources to serve loads within ERCOT. Unplanned Service is also available under this Part IV to an ERCOT Power Supplier to enable the delivery of energy purchased by a Load Serving Entity from an ERCOT Power Supplier in order to serve loads within ERCOT.
36.2 Nature of Transmission Service:
Scope of Service. The Ttransmission Sservice offered under this Part IV allows Transmission Customers to use the ERCOT Transmission Network for the delivery of the output of power and energy Planned Rresources to serve loads within ERCOT. and for the delivery of the output of Unplanned Resources to serve loads within ERCOT. The Transmission Customer must make arrangements for service with all other ERCOT Transmission Providers in accordance with Chapter 25. (b) Planned Service. Service uUnder this Part IV, as contemplated by Chapter 25, a Transmission Customer shall have the right, as contemplated by Chapter 25, to use the ERCOT Transmission Network for the delivery of electricity from Planned resources to loads located inside ERCOT on a basis similar to the use made by CPL and WTU of the Transmission System to reliably serve their native load customers inside ERCOT. Transmission Customers taking transmission service under this Part IV must arrange Ancillary Services pursuant to the ERCOT Protocols. Service over the ERCOT Transmission Network for the delivery of electricity from such Planned Resources shall have priority over all Unplanned Service. The ERCOT ISO shall determine priority of Unplanned Service transactions. (c) Unplanned Service. Under this Part IV, a Transmission CustomerTransmission Customer may use the ERCOT Transmission Network to deliver electricity to the Transmission CustomerTransmission Customer's ERCOT loads from resources that have not been designated as the Transmission CustomerTransmission Customer's Planned Resources. CPL and WTU shall transmit such electricity if sufficient transmission capacity is available in the CPL/WTU Transmission System to support the requested service.
37 Availability of Transmission Service
37.1 General Conditions: In accordance with the provisions of this Tariff, CPL and WTU shall make ERCOT Regional Transmission Service available to any Eligible Customer on a non-discriminatory basis.
37.2 Transmission Service Requirements: As a condition to obtaining Transmission Service under this Part IV, a Transmission Customer that owns electric facilities in ERCOT shall execute Interconnection Agreements with CPL and WTU and other ERCOT Transmission Providers to which such customer is physically connected. The Transmission Customer shall either:
(a) operate as a Control Area under applicable guidelines of the NERC and the ERCOT ISO; or
(b) satisfy its Control Area requirements, including the provision of all ERCOT Ancillary Services, by contracting with CPL and WTU or by purchasing the necessary Ancillary Services from another provider of such services, in accordance with Good Utility Practice.
CPL and WTU shall not unreasonably refuse to accept a Transmission Customer's contractual arrangements with another entity for ERCOT Ancillary Services.
37.3 Transmission Provider Responsibilities: CPL and WTU shall plan, construct, operate and maintain the CPL/WTU Transmission System in accordance with Good Utility Practice in order to provide Transmission Customers with ERCOT Regional Transmission Planned Service over their the CPL/WTU Transmission System in accordance with this Tariff. CPL and WTU shall, include each such Transmission Customer's ERCOT load in their transmission system planning and shall, consistent with Good Utility Practice, endeavor to construct and place into service transmission capacity to ensure adequacy and reliability of the transmission network, adequate to deliver power from the Transmission Customer's Planned Rresources to serve the Transmission Customer's Native Lload Customers in ERCOT. CPL and WTU shall plan, construct, operate, and maintain facilities that are needed to relieve transmission constraints, as recommended by the ERCOT ISO and approved by the PUCT, in order to provide service under this Part IV.
37.4 Transmission Customer Redispatch Obligation: As a condition to receiving Transmission Service under this Part IV, a Transmission Customer shall be deemed to have agreed to redispatch its resources to enable the provision of Planned Service to or for third parties. Any such redispatch of resources under this Part IV shall be on a non-discriminatory basis as between all Transmission Customers and Transmission Providers.
37.5 Reactive Power: The obligation to provide transmission service includes the obligation to provide reactive power support to maintain adequate system voltage support and control.
37.6 Priority of Transmission Service Applications:
(a) Planned Service shall have priority over Unplanned Service, and annual Planned Service shall have priority over Planned Service of a shorter duration.
(b) Subject to the foregoing priorities, completed applications for Planned or Unplanned Service filed earlier with the ERCOT ISO shall have priority over applications that are filed later.
(c) Where a Transmission Customer is using annual Planned Service for a resource that becomes unavailable due to an unplanned outage or the expiration of a power supply contract, the Transmission Customer shall have priority, in using the same transmission capacity to transmit power from a replacement resource, over other requests for Unplanned Service or Planned Service of a shorter duration.
37.47 Construction of New Facilities: If additional transmission facilities or interconnections between electric utilities are needed to provide transmission service pursuant to a request for such service, the Transmission Provider, to the extent the constraint exists on the CPL/WTU Transmission System, shall construct or acquire the facilities necessary to permit the transmission service to be provided, unless the ERCOT ISO identifies an alternative means of providing the transmission service that is less costly, operationally sound, and relieves the transmission constraint at least as efficiently as would the construction of additonal transmission facilities. determines that redispatch or other more economical means of making transmission capacity available will permit the requested transmission service to be providedIf additional facilities are needed to provide ancillary services to a customer requesting such service, the ancillary service provider shall acquire the facilities necessary to permit the ancillary service to be provided.
(1) If, in order to provide ancillary services, the Transmission Provider must construct new facilities, the ancillary services customer may be required to enter a long-term contract for ancillary service or make a contribution in aid of construction to cover all or part of the cost of acquiring the new facilities to the extent that the acquisition of the additional facilities is for the customer’s benefit.
(2)(1) When an eligible transmission service customer requests transmission service for a new generating source that is planned to be interconnected with the CPL/WTU Transmission System, the Transmission Customer shall be responsible for the cost of installing step-up transformers to transform the output of the generator to a transmission voltage level and a protective device at the point of interconnection capable of electrically isolating the generating source owned by the transmission service customer. The Transmission Provider shall be responsible for the cost of installing any other interconnection facilities that are designed to operate at a transmission voltage level and any other transmission system upgrades on its transmission system that may be necessary to accommodate the requested transmission service.
(a) The Transmission Provider may require the Transmission Customer to pay a reasonable deposit, or provide another means of security, to cover the costs of planning, licensing, and constructing any new transmission facilities that will be required in order to provide the requested service.
(b) If the new generating source is completed and the Transmission Customer begins to take the requested transmission service, the Transmission Provider shall return the deposit or security to the Transmission Customer. If the new generating source is not completed and new transmission facilities are not required, the Transmission Provider may retain as much of the deposit or security as is required to cover the costs it incurred in planning, licensing, and construction activities related to the planned new transmission facilities. Any repayment of a cash deposit shall include interest calculated in the manner described in 18 C.F.R. § 35.19(a).
(3)(2) Curtailment of service. In an emergency situation, as determined by the ERCOT ISO and at its direction, the Transmission Provider may interrupt transmission service on a non-discriminatory basis, if necessary, to preserve the stability of the transmission network and service to customers. Such curtailments shall be carried out in accordance with Part IV of this Tariff ., and the ERCOT Protocols.
37.8 Resale of Transmission Rights:
A Transmission Customer that holds transmission and ancillary service rights under this Part IV may resell those rights to another eligible Transmission Customer. The entity to whom such rights are resold shall enter into an Interconnection Agreement and a Service Agreement with the Transmission Provider. The reselling customer shall remain liable for the performance of all obligations under its Service Agreement with the Transmission Provider, except as specifically agreed to by the Parties through an amendment to the Service Agreement.
37.9 Scheduling:
The Transmission Provider shall schedule a Transmission Customer’s resources and accommodate changes to schedules requested by Transmission Customers. The Transmission Provider shall implement requested schedules and changes to schedules for third-party Transmission Customers upon the same terms and conditions and within the same time frames the Transmission Provider applies to itself in scheduling resources to serve native load customers.
38 Initiating Service
38.1 Each Load Serving Entity Eligible Customer or ERCOT Power Supplier that uses the ERCOT Transmission Network to serve its Native Load customers in ERCOT from its from Planned or Unplanned resources, or in making sales of energy to a third party in ERCOT from Planned or Unplanned its resources, may apply for Ttransmission Sservice pursuant to this Part IV and the ERCOT Protocols. The Transmission Customer and CPL and WTU shall provide the information that is required under this Part IV to the ERCOT ISO, with a copy to CPL and WTU.
38.21 Conditions Precedent for Receiving Service: Subject to the terms and conditions of Part IV of this Tariff and in accordance with the ERCOT Protocols, CPL and WTU will provide Ttransmission Sservice to any Eligible Customer that requests service, provided that:
(a) the Eligible Customer has completed an Application for service as provided under this Section 38;
(b) the Eligible Customer and CPL and WTU have completed the technical arrangements contemplated by this Section 38;
(c) if the Eligible Customer operates electrical facilities that are connected to the facilities of CPL or WTU, the Eligible Customer has executed all Interconnection Agreements required for service under this Tariff or, if necessary, requested in writing pursuant to Section 38.140 of this Tariff that a Transmission Provider file a proposed unexecuted Interconnection Agreement with the regulatory agency having jurisdiction;
(d) the Eligible Customer has arranged for ERCOT Ancillary Services necessary for the transaction;
(e) if the Eligible Customer is responsible for serving wholesale load, it has agreed to maintain or cause to be maintained a power factor of 95% or greater at each of its points of interconnection to the ERCOT Transmission Network; and
(f)(d) the Transmission Customer has either executed a Service Agreement or requested in writing pursuant to Section 38.140 of this Tariff that CPL and WTU file an unexecuted Service Agreement with the Commission.
38.32 Application Procedures for Annual Planned ERCOT Regional Transmission Service:
(a) An Eligible Customer requesting annual Planned ERCOT Regional Transmission sService under Part IV of this Tariff must submit an Application for service. to the ERCOT ISO by October 1 in the year preceding the year in which service is to commence. A Completed Application shall provide the information required in subsection (b) below. The Eligible Customer shall provide the information that is required under subsection (b) below to the ERCOT ISO, with a copy to CPL and WTU.
(b) The Eligible Customer must provide all information deemed necessary by the ERCOT IO to evaluate the request for transmission service. The following information shall be provided in connection with an Application for service under Part IV of this Tariff:
(i) The identity, address, e-mail address, telephone number and facsimile number of the Eligible Customer requesting service and the name of the person to whom communications regarding the Application should be directed.
(ii) A statement that the party requesting service is, or upon commencement of service will be, an Eligible Customer under this Tariff.
(iii) A description of the ERCOT load to be served. The description shall include a five-year forecast of summer and winter peak loads and resource requirements beginning with the first calendar year after the service is scheduled to commence. The ERCOT ISO will establish the nature, detail and format of the information that must be provided.
(iv) A description of Planned Resources (current and five-year projection), which shall include, for each such resource:
- Location, unit size and amount of capacity from a generating unit to be designated as a Planned Resource.
- Reactive power capability (both leading and lagging) of each such generating unit.
- Operating restrictions relating to each such generating unit, including:
a) any period of restricted operations during the year;
b) minimum loading level;
c) normal operating level; and
d) any must-run designations required for system reliability or contract reasons.
(v) A description of purchased power designated as a Planned Resource, including source of supply, Control Area location, transmission arrangements and, if applicable, Point(s) of Receipt into ERCOT.
(vi) To the extent arrangements have been made for ERCOT Ancillary Services, the identity of the providers of ERCOT Ancillary Services shall be provided.
(vii) The service commencement date of the requested Transmission Service and service termination date or duration of service.
(viii) Where the Eligible Customer serving the ERCOT load does not own the Planned Resource, a copy of the contract between the Eligible Customer and the owner of the Planned Resource, which may be redacted to remove market-sensitive information not needed in assessing the request for Transmission Service.
(ix) Any other information designated by the ERCOT ISO as reasonably necessary to evaluate the ability of the ERCOT Transmission Network to accommodate reliably the requested service.
(c) Chapter 25 requires the ERCOT ISO to provide to affected Transmission Providers the information needed for them to evaluate the request for Transmission Service.
(d)(c) Chapter 25 requires the ERCOT ISO to acknowledge a request for service within ten days of receipt. When the request is complete, the acknowledgment will include a date by which a response will be sent to the Eligible Customer and a statement of any fees associated with responding to the request (e.g., fees for system studies).
(e)(d) If an Application fails to meet the requirements of this Tariff provide the ERCOT IO with all information deemed necessary, Chapter 25 requires the ERCOT ISO to notify the Eligible Customer requesting service within 15 business days of receipt thereof and specify the reasons for such failure. Wherever possibleChapter 25 requires the ERCOT ISO, wherever possible, to attempt to remedy deficiencies in an Application through informal communications with an Eligible Customer.
(f)(e) If a System Impact Study is required, upon approval of the requesting Transmission Customer, Chapter 25 requires the ERCOT ISO to initiate perform or direct the Transmission Provider to prepare such a study. If the ERCOT ISO concludes that the CPL and WTU Transmission System is adequate to accommodate the request for service, either in whole or in part, or that no costs are likely to be incurred for new transmission facilities or upgrades, the Transmission Provider will tender a Service Agreement for ERCOT Regional Transmission Service, within 15 business days of completion of the System Impact Study.
(g)(f) If the ERCOT ISO determines as a result of a System Impact Study that additions or upgrades to the CPL/WTU Transmission System are needed to supply the Transmission Customer's forecasted requirements for ERCOT Regional Transmission Service, the Transmission Provider will, upon approval of the requesting Transmission Customer, initiate a Facilities Study. When completed, a Facilities Study will include an estimate of the cost of any required facilities or upgrades, and the time required to complete such construction and initiate the requested service.
(g) Unplanned Service renewed or extended for a duration of more than 30 days may converted to Planned Service upon approval of an Application submitted pursuant to this Section 38.4 of this Tariff. The participants in such a transaction shall be responsible for the costs of any required feasibility analysis.
(g) Chapter 25 requires that when a Transmission Customer applies for tranmission service for a new resource under this section, the ERCOT IO shall notify affected Transmission Providers of the application and request comments concerning the scope of any System Impact Study.
(h) Chapter 25 requires the ERCOT IO to complete the System Impact Study and provide the results to the Transmission Customer within 60 business 90 days after the receipt of an executed study agreement and receipt from the Transmission Customer of all the data necessary to complete the study. In the event the ERCOT IO is unable to complete the study within the 690 day period, it will provide the Transmission Customer a written explanation of when the study will be completed and the reason for the delay.
(i) The requesting Transmission Customer shall be responsible for the cost of the System Impact Study and shall be provided with the results thereof, including relevant work papers.
A)
38.4 Application Procedures for Other Planned Service:
(a) An Eligible Customer may request monthly, weekly or daily Planned Service (“Other Planned Service”) in connection with a change in its designated Planned Resources or other transmission needs.
(b) The Application shall supply information similar to that required in an Application for annual Planned Service for the period during which Other Planned Service is to be effective.
(b) If the ERCOT ISO determines that the service can be provided and a System Impact Study is not required, Chapter 25 requires the ERCOT ISO to notify the requesting Eligible Customer and to tender Transmission Service.
38.5 Application for Unplanned ERCOT Regional Transmission Service: Eligible Customers wishing to use the ERCOT Transmission Network for Unplanned Service to serve ERCOT loads must submit a request for such service to the ERCOT ISO. The duration for Unplanned Service shall be from one hour to 30 days. In no case shall Unplanned Service transactions be accepted for consideration more than 30 days in advance of the proposed service commencement date.
(a) Requests for Unplanned Service must be submitted with at least the lead times prescribed in clauses (i)-(iv) of this subparagraph:
(i) for hourly transactions, at least 20 minutes in advance;
(ii) for daily transactions, no later than by 2:00 p.m. the day before the transaction is to commence;
(iii) for weekly transactions, at least two days in advance; and
(iv) for monthly transactions, at least four days in advance.
(b) A response to a request for Unplanned ERCOT Regional Transmission Service will be made by the ERCOT ISO as soon as practical after the request is made. Responses to requests for Unplanned Service shall be provided no later than the times prescribed in clauses (i)-(iv) of this subparagraph:
(i) for hourly transactions, within 10 minutes of the request for service;
(ii) for daily transactions, within four hours of the request for service;
(iii) for weekly transactions, within 24 hours of the request for service; and
(iv) for monthly transactions, within two days of the request for service.
(c) A request for Unplanned Service will be analyzed first for the next hour and allowed to start if no violations of Good Utility Practice are anticipated.
(d) The following information shall be provided in connection with any request for Unplanned ERCOT Regional Transmission Service:
(i) The identity, address, e-mail address, telephone number and facsimile number of the Eligible Customer requesting service and the person to whom communications regarding the Application for Unplanned Service should be directed.
(ii) A statement that the party requesting service is, or upon commencement of service will be, an Eligible Customer under this Tariff.
(iii) A description of the ERCOT load to be served and the Unplanned Resources serving such load, which shall include, for each resource:
- Location, unit size and amount of capacity from each generating unit to be designated as a resource.
- Reactive power capability (both leading and lagging) of each such generating unit.
- Operating restrictions relating to each such generating unit, including minimum loading level, and normal operating level.
- A description of purchased power designated as a resource including source of supply, Control Area location, transmission arrangements and, if applicable, Point(s) of Receipt into ERCOT.
- To the extent that arrangements have been made for ERCOT Ancillary Services, the identity of the providers of such services.
- When service is to begin and the anticipated duration.
- If the Unplanned Service will affect the Transmission Customer's use of Planned Resources, a statement of the effect of Unplanned Service on the Transmission Customer's use of Planned Resources.
(e) Chapter 25 requires the ERCOT ISO to make every reasonable attempt to begin any requested Unplanned Service transaction as soon as possible to conform to the requested commencement time. Operating restrictions, anticipated redispatch needs, the potential for Curtailment, and other related information, if known, will be communicated to the requesting Eligible Customer to determine whether the transaction is still feasible for the Eligible Customer given the known restrictions.
(f) Chapter 25 requires the ERCOT ISO, at its discretion, to take requests outside the time frames prescribed in subsection 38.5(a) if practical given the current or expected operating conditions on the ERCOT Transmission Network. The ERCOT ISO may set longer notification and response times than those prescribed in subsections 38.5(a) and (b) during a system emergency, and shall periodically review the notification and response times.
38.6 System Impact Study:
(a) When a Transmission Customer applies for Planned Service for a new Planned Resource pursuant to Section 39.2 of this Tariff, Chapter 25 requires the ERCOT ISO to notify affected Transmission Providers in ERCOT of the Application and request comments from them concerning the scope of any System Impact Study. The Transmission Customer and the ERCOT ISO shall execute a joint study agreement for performing a System Impact Study to determine the feasibility of integrating such new Planned Resource into the ERCOT Transmission Network, and whether any upgrades of facilities providing transmission or ERCOT Ancillary Services are needed. The ERCOT ISO will perform the System Impact Study.
(b) In performing a System Impact Study, Chapter 25 requires the ERCOT ISO to apply the same methods and criteria that CPL and WTU employ in integrating new resources or new loads.
(c) Chapter 25 requires the ERCOT ISO to complete the System Impact Study within 60 days after the date of receipt of an executed study agreement and receipt from the Transmission Customer of all the data necessary to complete the study. In the event the ERCOT ISO is unable to complete the study within the 60-day period, it will provide the Transmission Customer a written explanation of when the study will be completed and the reasons for the delay.
(d) The requesting Transmission Customer shall be responsible for the cost of the System Impact Study and shall be provided with the results thereof, including relevant workpapers.
(e) Chapter 25 requires the ERCOT ISO to use a methodology consistent with Good Utility Practice to conduct a System Impact Study and to coordinate with the affected Transmission Providers as needed to determine the most efficient means for all ERCOT utilities to assure feasibility of Transmission Service.
38.73 Facilities Study:
(a) bBased on the results of the System Impact Study, the Transmission Provider shall perform, or cause to be performed, pursuant to an executed Facilities Study agreement with the Transmission Customer, a Facilities Study addressing the detailed engineering, design and cost of transmission and ERCOT Ancillary Services facilities required to provide the requested Transmission Service.
(b) The Transmission Provider will complete the Facilities Study as soon as reasonably practicable using information developed in the System Impact Study. Upon completion of the Facilities Study, the Transmission Provider shall notify the Transmission Customer whether the Transmission Provider considers that a contribution in aid of construction is appropriate and the amount of the contribution that the Transmission Customer should make. The Transmission Provider shall base its request on the information in the System Impact Study and the Facilities Study and the provisions in this Part IV.
(c) The Transmission Customer shall be responsible for the reasonable cost of the Facilities Study pursuant to the terms of the Facilities Study agreement and shall be provided with the results thereof, including relevant workpapers.
(d) The Transmission Provider shall be responsible for the costs of any Facilities Study undertaken to determine the engineering, design and cost of facilities associated with the addition of new resources used to serve load of CPL or WTU. Such costs will be booked separately by CPL and WTU, as the case may be.
(e) When completed, the Facilities Study will include a good faith estimate of (i) the cost of Direct Assignment Facilities to be charged to the Eligible Customer, and (ii) the Eligible Customer’s appropriate share of the cost of any required facilities for which the Eligible Customer is responsible under Chapter 25, and (iii) the time required to complete such construction and initiate the requested service. The Eligible Customer shall provide the Transmission Provider with a letter of credit or other reasonable form of security acceptable to the Transmission Provider equivalent to the costs of new facilities or upgrades consistent with commercial practices as established by the Uniform Commercial Code. The Eligible Customer shall have thirty (30) days to execute a Service Agreement or request the filing of an unexecuted Service Agreement and provide the required letter of credit or other form of security or the request no longer will be a Completed Application and shall be deemed terminated and withdrawn
38.84 Technical Arrangements to be Completed Prior to Commencement of Service: Service under this Tariff shall not commence until the installation of all equipment specified in the Interconnection Agreement has been completed in a manner consistent with guidelines adopted by the national reliability organization and the ERCOT ISO, except that the Transmission Provider shall provide the requested Transmission Service to the extent that such service does not impair the reliability of other Transmission Service. The Transmission Provider shall exercise reasonable efforts, in coordination with the Transmission Customer, to complete such arrangements as soon as practical prior to the service commencement date.
38.95 Transmission Customer Facilities: The provision of Transmission Service shall be conditioned upon the Transmission Customer's constructing, maintaining and operating the facilities on its side of each point of interconnection to the ERCOT Transmission Network that are necessary reliably to interconnect and deliver power from a resource to the ERCOT Transmission Network and from the ERCOT Transmission Network to the Transmission Customer's loads.
38.106 Transmission Arrangements for Resources Located Outside of the ERCOT Region : It shall be the Transmission Customer’s responsibility to make any transmission arrangements necessary for delivery of capacity and energy produced from a resource outside of ERCOT to the interconnection with the SPP ERCOT. The Transmission Provider shall undertake reasonable efforts to assist the Transmission Customer in coordinating and scheduling arrangements with connecting systems within ERCOT.
38.117 Changes in Service Requests: Under no circumstances shall a Transmission Customer’s decision to cancel or delay the addition of a new Planned Rresource in any way reduce or relieve the Transmission Customer’s obligation to pay the costs expended by the Transmission Provider to conduct the Facility Study. construct new facilities required to receive power from the new Planned Resource. Upon receipt of a Transmission Customer’s written notice of such a cancellation or delay, the Transmission Provider will use the same reasonable efforts to mitigate the costs and charges owed by the Transmission Customer to the Transmission Provider as it would to reduce its own costs and charges.
38.128 Annual Load and Resource Information Updates: By October 1 of each year, a The Transmission Customer shall provide the Transmission Provider and the ERCOT ISO with annual updates of load and resource forecasts. consistent with those included in its Application for Transmission Service. The Transmission Customer also shall provide the Transmission Provider and the ERCOT ISO with timely written notice of material changes in any other information provided in its Application relating to the Transmission Customer’s planned load, resources, its transmission system or other aspects of its facilities or operations affecting the Transmission Provider’s ability to provide reliable service under this Tariff. Each of CPL and WTU will provide the ERCOT ISO similar information. by October 1 of each year.
38.139 Termination of Planned Transmission Service: A Transmission Customer may terminate Planned Sservice under this Tariff after providing the Transmission Provider and ERCOT with written notice of the Transmission Customer's intention to terminate. A Transmission Customer's provision of notice to terminate service under this Tariff shall not relieve the Transmission Customer of its obligation to pay the Transmission Provider any rates, charges, or fees, including contributions in aid of construction, or for service previously provided under the applicable interconnection service agreement and that are owed to the Transmission Provider as of the date of termination.
38.140 Initiating Service in the Absence of an Executed Service Agreement: If the Transmission Provider and a Transmission Customer requesting Transmission Service under this Part IV cannot agree on all the terms and conditions of the Service Agreement, the Transmission Provider shall file with the Commission, no later than thirty (30) days after the date the Transmission Customer provides written notification directing the Transmission Provider to file, an unexecuted Service Agreement containing terms and conditions deemed appropriate by the Transmission Provider for such requested Transmission Service. Upon acceptance for filing by the Commission of such unexecuted agreement, the Transmission Customer shall be deemed to have agreed to (i) compensate the Transmission Provider at whatever rate the Commission ultimately determines to be just and reasonable, and (ii) comply with all other terms and conditions of this Tariff.
39 Planned Resources
A Transmission Customer must designate Planned Resources in a timely fashion on an annual planning basis so that deficiencies in the ERCOT Transmission Network may be identified and plans may be formulated by Transmission Providers to correct such deficiencies.
39.1 Designation of Planned Resources: Planned Resources shall include generation owned, controlled or purchased by the Transmission Customer and used to serve its loads located in ERCOT. The minimum capacity designated as Planned Resources shall be consistent with ERCOT guidelines or the amount specified by the ERCOT ISO.
39.2 Designation of New Planned Resources: A Transmission Customer may designate a new Planned Resource by providing the ERCOT ISO notice of such designation. Until the Transmission Provider has completed any transmission facilities or upgrades determined in accordance with Section 40 of this Tariff to be necessary for planned delivery from a new Planned Resource, delivery of power from such resource will be provided by the Transmission Provider, but only to the extent that such service does not impair the reliability of other Planned Service transactions or other previously committed Unplanned Service transactions having a higher service priority. Notice of a Transmission Customer's designation of a new Planned Resource shall include engineering and technical information, as contemplated by Section 38.2 above, sufficient to permit the ERCOT ISO to perform a System Impact Study and the Transmission Provider to perform a Facilities Study addressing the transmission requirements associated with delivery of such new Planned Resource to the Transmission Customer's load within ERCOT.
4039 Rates and Charges
A Transmission Customer taking ERCOT Regional Transmission Service under this Tariff shall pay the Transmission Provider for any Direct Assignment Facilities, and applicable study costs, and distribution services charges consistent with Commission policy, along with the following charges:
4039.1 Demand Charge for Planned ERCOT Regional Transmission Service: A Transmission Customer taking Annual Planned ERCOT Regional Transmission Service under Part IV of this Tariff shall pay the Transmission Provider a monthly demand charge. The monthly demand charge under this Tariff for Annual Planned ERCOT Regional Transmission Service shall be consist of one-twelfth of the annual access fee the charges set forth in Attachment K.. A Transmission Customer taking Other Planned Service under Part IV of this Tariff shall pay the Transmission Provider a charge based on the applicable access rate multiplied by the MW of demand the Transmission Customer requests to serve using the Other Planned Service.
40.2 Access Fee: The access fee payable by a Transmission Customer taking Planned Service under Part IV of this Tariff shall be calculated in the manner specified in Attachment K to this Tariff.
40.3 Loss Charges for Planned Service: Except as provided in Section 28.5 of this Tariff, a Transmission Customer taking Planned Service under this Part IV shall also compensate the Transmission Provider for losses associated with Planned Service in accordance with the schedule of loss charges developed by the ERCOT ISO for such purpose.
40.4 Charges for Unplanned Service: A Transmission Customer taking Unplanned Service under this Part IV shall not incur a monthly demand charge but shall pay loss compensation charges in accordance with the loss matrices for Unplanned Service produced by ERCOT.
41 Load Shedding and Curtailments
41.1 Procedures:
(a) The Transmission Provider and the ERCOT ISO shall establish non-discriminatory emergency Load Shedding and Curtailment procedures for responding to emergencies on the ERCOT Transmission System.
(b) The Transmission Provider and Transmission Customers will comply with the Load Shedding and Curtailment procedures thus established.
(c) The Transmission Provider and Transmission Customers will implement such procedures during any period when the ERCOT ISO determines that a transmission capacity constraint exists and such procedures are necessary to alleviate the constraint.
(d) The Transmission Provider will notify the ERCOT ISO in a timely manner of any scheduled transmission facility interruption (e.g., scheduled maintenance).
41.2 Transmission Constraints and Redispatch:
(a) During any period when the ERCOT ISO determines that a transmission constraint exists on the CPL/WTU Transmission System or the ERCOT Transmission Network, and such constraint may impair the reliability of a Transmission Provider's system or adversely affect the operations of either a Transmission Customer or a Transmission Provider, Chapter 25 requires the ERCOT ISO to take such actions, consistent with Good Utility Practice, that are reasonably necessary to maintain the reliability of the CPL/WTU Transmission System and the ERCOT Transmission Network and avoid interruption of service. Chapter 25 requires the ERCOT ISO to notify affected Transmission Providers and Transmission Customers of the actions being taken. In these circumstances, the Transmission Provider and Transmission Customers shall take such action as the ERCOT ISO directs.
(b) Any interruption shall be based on operational factors and shall not give a higher priority to the Transmission Provider’s native load customers than to its Transmission Customers taking transmission service under this Part IV. Priority shall be given to Transmission Customers in accordance with this Part IV.
(c) The Transmission Provider shall restore service to all Transmission Customers as quickly as possible.
(d) The ERCOT ISO shall determine whether a proposed redispatch is cost-effective and whether a Transmission Customer must redispatch its generating resources to facilitate a transaction.
(e) To the extent the ERCOT ISO determines that the reliability of the ERCOT Transmission Network can be maintained by redispatching resources, or when redispatch arrangements are necessary to facilitate wholesale generation and transmission transactions for an Eligible Customer under Part IV of this Tariff, the Transmission Provider or the Transmission Customer will initiate procedures to redispatch their resources, as directed by the ERCOT ISO. The obligation to redispatch resources includes the obligation to redispatch non-utility resources on which a Transmission Customer relies.
(f) To the greatest extent possible, any redispatch shall be made on a least-cost non-discriminatory basis. Any redispatch under this section will provide for equal treatment among Transmission Customers, subject to the priorities set out in this Part IV. If the ERCOT ISO determines that the Transmission Provider will not have adequate transmission capacity to satisfy the full amount of a valid request for Planned Service, the Transmission Provider nonetheless shall be obligated to offer and provide the portion of the requested Planned Service that can be accommodated without addition of any facilities. This obligation includes a duty to redispatch resources to increase the level of Planned Service that may be provided. However, the Transmission Provider shall not be obligated to provide the incremental amount of requested Planned Service to the extent that the provision of the service requires the addition of facilities or upgrades to the CPL/WTU Transmission System until such facilities or upgrades have been placed in service.
41.3 Cost Responsibility for Relieving Capacity Constraints:
(a) CPL and WTU shall provide redispatch services on a non-discriminatory basis to all Transmission Customers taking service under Part IV of this Tariff when necessary to preserve system reliability or to alleviate transmission constraints that impede wholesale generation and transmission transactions.
(b) The price for redispatch services for Annual Planned Service transactions shall be based on the cost of providing the service, which shall be allocated among Transmission Customers in proportion to each Transmission Customer’s share of the transmission cost of service associated with the ERCOT Transmission Network, as determined by the PUCT under Chapter 25. For redispatch required to accomplish an Annual Planned Service transaction, the Transmission Provider shall provide information documenting the costs incurred to provide the service to the ERCOT ISO. This information shall be available to affected persons.
(c) The cost of redispatch service for other transactions (including Planned Service of a duration of less than a year) shall be borne by the Transmission Customer for whose benefit the redispatch is made. Chapter 25 requires ERCOT Power Suppliers to provide binding advance bids for redispatch services for Unplanned Service transactions. Participants in Unplanned Service transactions shall be promptly notified by the ERCOT ISO when their transactions may be or have been continued through redispatch; shall be informed of the cost of the redispatch measures taken; and shall have the opportunity to abandon or curtail their transactions to avoid additional redispatch costs.
(d) To the extent that CPL or WTU redispatch non-utility resources on which they rely to serve load pursuant to this Part IV, the compensation for such services shall be consistent with this Part IV
39.2 Commercial Terms for Transmission Service:
Billing and Payment: Within a reasonable time after the first day of each month, the Transmission Provider shall issue invoices for the prior month’s transmission service to the Transmission Customers.
(1) An invoice for transmission service shall be paid so that the Transmission Provider will receive the funds by the 35th calendar day after the date of issuance of the invoice, unless the Transmission Provider and the Transmission Customer agree on another mutually acceptable deadline. All payments shall be made in immediately available funds payable to the Transmission Provider or by wire transfer to a bank named by the service provider or by other mutually acceptable terms.
(2) Interest on any unpaid amount shall be calculated by using the interest rate applicable to overbilling and underbilling set by the commission and compounded monthly. Interest on delinquent amounts shall be calculated from the due date of the bill to the date of payment. When payments are made by mail, bills shall be considered as having been paid on the date of receipt by the Transmission Provider.
(3) In the event the Transmission Customer fails, for any reason other than a billing dispute as described in subparagraph (A) of this paragraph, to make payment to the Transmission Provider on or before the due date, and such failure of payment is not corrected within 30 calendar days after the Transmission Provider notifies the Transmission Customer to cure such failure, the customer shall be deemed to be in default.
(A) Upon the occurrence of a default, the Transmission Provider may initiate a proceeding with the cCommission to terminate service. If the commission finds that a default has occurred the transmission service customer shall pay to the Transmission Provider an amount equal to two times the amount of the payment that the customer fails to pay in addition to any other remedy ordered by the commission. In the event of a billing dispute between the Transmisssion Provider and the Transmission Customer, the Transmission Provider will continue to provide service during the pendency of the proceeding, as long as the Transmission Customer:
(i) continues to make all payments not in dispute;
(ii) pays into an independent escrow account the portion of the invoice in dispute, pending resolution of such dispute.
(B) If the Transmission Customer fails to meet the requirements in subparagraph (A) of this paragraph, then the Transmission Provider will provide notice to the Transmission Customer and to the commission of its intention to terminate service.
(C) Any dispute arising in connection with the termination or proposed termination of service shall be referred to the alternative dispute resolution process described in Chapter 25.
410.4 System Reliability
(a) Notwithstanding any other provision of Part IV of this Tariff, the Transmission Provider reserves the right, consistent with Good Utility Practice and on a non-discriminatory basis, to interrupt Transmission Service provided under this Part IV without liability on the part of the Transmission Provider for the purpose of making necessary adjustments to, changes in, or repairs to its lines, substations and other facilities, or where the continuance of Transmission Service would endanger persons or property.
(b) In the event of any adverse condition or disturbance on the CPL/WTU Transmission System or on any other system directly or indirectly interconnected with the CPL/WTU Transmission System, the Transmission Provider, consistent with Good Utility Practice, also may interrupt Transmission Service provided under this Part IV on a non-discriminatory basis in order to limit the extent or damage of such adverse condition or disturbance, prevent damage to generating or transmission facilities, or expedite restoration of service.
(c) The Transmission Provider will give the ERCOT ISO, affected Transmission Customers and affected ERCOT Power Suppliers as much advance notice as is practicable in the event of any such interruption.
(d) A Transmission Customer's failure to respond to established emergency Load Shedding and Curtailment procedures to relieve emergencies on the ERCOT Transmission Network may result in the Transmission Customer's being deemed by the Transmission Provider to be in default and may result in the termination of transmission service under this Part IV.
421 ERCOT Ancillary Services
421.1 Responsibility for ERCOT Ancillary Services: Under Section 4: Scheduling of the ERCOT Protocols, QSEs are responsible for submitting to ERCOT Balanced Schedules for Obligations and Supply, including the Ancillary Services Obligation for Regulation Service-Up, Regulation Service-Down, Responsive Reserve Service and Non-Spinning Reserve Service. A Transmission Customer serving load in ERCOT may purchase such ERCOT Ancillary Services, either directly or through an agent, from CPL, WTU, another generation resource, or from the ERCOT Ancillary Services Market. Unless CPL, WTU or their agent has specifically agreed to act as the QSE for a Transmission Customer serving load in ERCOT, CPL and WTU shall not be responsible under this Tariff for complying with any Ancillary Service Obligation that ERCOT imposes with respect to such Customer. A Transmission Customer is responsible for obtaining or providing necessary ERCOT Ancillary Services. The ERCOT ISO shall determine whether an Eligible Customer has secured ERCOT Ancillary Services that are adequate for a proposed transaction, shall notify the Transmission Customer if additional ERCOT Ancillary Services are needed, and shall notify affected Transmission Providers of the ERCOT Ancillary Services arrangements that the ERCOT Ancillary Services Customer has made, including the services being provided and the identity of the service providers. The Transmission Provider shall not unreasonably refuse to accept contractual arrangements with another entity for ERCOT Ancillary Services.
(a) An Eligible Customer may designate an agent to represent it in making arrangements for ERCOT Ancillary Services under this Section 42.
(b) A person who requires ERCOT Ancillary Services to utilize Transmission Service within ERCOT or to transmit power across the HVDC Facilities to serve load in ERCOT is an Eligible Customer under this section.
(c) A Transmission Customer may purchase the ERCOT Ancillary Services necessary for prudent utility operation from the Transmission Provider or from another supplier, or supply the service to itself in accordance with the provisions of Section 3 of this Tariff. Any person that knowingly makes use of ERCOT Ancillary Services required by the ERCOT ISO without the agreement of the person providing the service shall pay to the Service Provider an amount equal to three times the otherwise applicable charge. In no case shall the Transmission Provider knowingly provide such an ERCOT Ancillary Service without prior arrangements with the ERCOT Ancillary Services Customer nor shall the Transmission Provider unilaterally impose ERCOT Ancillary Services on an unwilling purchaser. An ERCOT Ancillary Services Customer that takes Transmission Service under Part II of this Tariff to serve its ERCOT Load under Part IV will take ERCOT Ancillary Services for such Part II transaction.
421.2 ERCOT Ancillary Services: Through December 31, 2001, Retail Electric Providers (REPs) taking transmission service under Part IV to deliver power and energy to retail customers connected to the distribution or transmission facilities of CPL or WTU in ERCOT shall have the option to purchase the ERCOT Ancillary Services contained in Service Schedules 9 through 12. Until the earlier of December 31, 2001 or the expiration of a customer's full or partial requirements service agreement, Service Schedules 9 through 12 shall also apply to those wholesale customers of CPL and WTU with such service agreements that provide for the Customer to take unbundled ancillary services. In all other cases Transmission Customers serving load in ERCOT will obtain ERCOT Ancillary Services through the markets for Ancillary Services operated by ERCOT. The specific ERCOT Ancillary Services, prices, and/or compensation methods offered by the Transmission Provider CPL and WTU under this Tariff are those that are described in the Service Schedules listed below:
Schedule 9--ERCOT Responsive ReserveRegulation Service-Up
Schedule 10--ERCOT Spinning ReserveRegulation Service-Down
Schedule 11--ERCOT Static SchedulingResponsive Reserve Service
Schedule 12--ERCOT Dynamic SchedulingNon-Spinning Reserve Service
Schedule 13--ERCOT Load Following
Schedule 14--ERCOT Load Regulation
Schedule 15--ERCOT Generation Schedule Imbalance
Schedule 16--ERCOT Load Schedule Imbalance
Schedule 17--ERCOT Schedule Backup
Schedule 18--ERCOT Automatic Backup
Schedule 19--ERCOT Emergency Energy
(a) If a Transmission Customer requests a service not listed in this section or the Transmission Provider intends to offer a service not listed in this section, the Transmission Provider may supply the service. In the case of a service requested by a Transmission Customer, the definition and price may be determined by negotiation between the Transmission Provider and the Transmission Customer. The service may be provided immediately upon the execution of a contract between the parties, but the service will be subject to approval by the Commission.
(b) If the Transmission Provider provides an ancillary service to a Part IV Transmission Customer not specified in its Tariff, it shall file a modification to the Tariff within 30 days of initiating the service and shall make the service available to all Part IV Transmission Customers on a non-discriminatory basis.
(c) The Transmission Provider may request limitations on its obligation to provide ancillary services, based on the size of the cost of acquiring the equipment necessary to provide a service, based on its use of tax-exempt financing instruments, if any, or for other good cause. The Transmission Provider will have the burden of establishing that any such limitation is reasonable.
(d) The Transmission Provider may not require the purchase of generation services from the Transmission Provider as a condition for the provision of ERCOT Ancillary Services or for discounts on such services. The purchase of power from a source shall not be contingent on purchase of ERCOT Ancillary Services from the same source. Bids or offers for ERCOT Ancillary Services shall not be bundled with a power sale.
421.3 Initiating ERCOT Ancillary Service: Prior to engaging in an ERCOT Ancillary Service transaction under this Part IVTariff, aeach ERCOT Ancillary Services Customer and the Transmission Provider shall have completed the technical arrangements contemplated by Section 412.5 below. In addition, the ERCOT Ancillary Services Customer shall:
(i) complete an Application for service as provided under Section 421.4 of this Tariff; and
(ii) execute a Service Agreement for ERCOT Ancillary Services under this Part IVTariff, or request in writing pursuant to Section 421.8 of this Tariff that CPL and WTU the Transmission Provider file an unexecuted Service Agreement with the Commission.
421.4 Application Procedures for ERCOT Ancillary Services:
(a) An ERCOT Ancillary Services Customer requesting ERCOT Ancillary Sservices under this Part IV Tariff must submit a written Application to the Transmission Provider by telefax or overnight delivery to:
American Electric Power Service Corporation
Attn: Director, Transmission and Interconnection Services
1 Riverside Plaza
Columbus, Ohio 43215-2373
A Completed Application shall provide the following information:
(i) the identity, address, telephone number, and facsimile number of the party requesting service;
(ii) a statement that the party requesting service is, or upon commencement of service will be, eligible for service under this Tariff;
(iii) the service requested, the proposed service commencement date and the term of the requested service; and
(iv) any other information that the Transmission Provider deems necessary for providing the requested ERCOT Ancillary Services.
A request to schedule ERCOT Ancillary Services must be submitted with at least the lead time prescribed below:
(1) to support hourly transactions, at least 20 minutes in advance of the commencement of the transaction;
(2) to support daily transactions, no later than 2:00 p.m. the day before the transaction is to commence;
(3) to support weekly transactions, at least two days in advance;
(4) to support monthly transactions, at least four days in advance; or
(5) to support annual Planned Service transactions, at least 15 days in advance.
(b) If an Application fails to meet the requirements of this section, the Transmission Provider shall notify the ERCOT Ancillary Services Customer Transmission Customer requesting service and specify the reasons for such failure. The response of the Transmission Provider to these requests shall include a statement of any fees associated with responding to the request.
(c) Unless the parties agree otherwise, responses to requests for ERCOT Ancillary Services shall be provided by the Transmission Provider to the ERCOT Ancillary Services Customer no later than the time prescribed in clauses (i)-(v) of this subsection:
(i) for hourly transactions, within 10 minutes of the request;
(ii) for daily transactions, within four hours;
(iii) for weekly transactions, within 24 hours;
(iv) for monthly transactions, within two days; or
(v) for annual Planned Service transactions, within seven days.
(d) Wherever possible, the Transmission Provider will attempt to remedy deficiencies in the Application or schedule request through informal communications with the requesting ERCOT Ancillary Services Customer.
(e) The Transmission Provider will not divulge information from any Application for service under this Part IV to its marketing personnel, its marketing affiliates, or persons buying or selling electricity in the bulk power market, except that it may provide information necessary to make arrangements for the service to an organizational entity involved in providing the service.
(f) During a system emergency, the ERCOT ISO may set longer notification and response times than those prescribed in subsections (a) and (c) of this section, and shall periodically review the notification and response times.
421.5 Technical Arrangements to be Completed Prior to Commencement of ERCOT Ancillary Services: The provision of ERCOT Ancillary Services shall be conditioned upon construction, maintenance and operation of facilities necessary reliably to interconnect and receive service from the Transmission Provider consistent with Good Utility Practice. Additional requirements may be applied by the Transmission Provider only if they are reasonably and consistently imposed to ensure the reliable operation of the systems of affected utilities and the Transmission Provider, are applied in a non-discriminatory manner, and have been approved by the ERCOT ISO. The Transmission Provider shall exercise reasonable efforts, in coordination with the ERCOT Ancillary Services Transmission Customer, to complete such arrangements as soon as practical prior to the service commencement date.
421.6 Termination of ERCOT Ancillary Services: An ERCOT Ancillary Services Customer may terminate its purchase of ERCOT Ancillary Services under this Part IV Tariff following written notice to the Transmission Provider of the ERCOT Ancillary Services Customer's intention to terminate. An ERCOT Ancillary Services Customer's provision of notice to terminate service under this section shall not relieve the ERCOT Ancillary Services Customer of its Such notice to terminate service under this section shall not relieve the Customer of its obligation to pay the Transmission Provider any rates, charges, or other fees, including contributions in aid of construction, for service previously provided under the applicable service agreement, and that are owed to the Transmission Provider as of the date of termination; nor shall such a notice relieve the ERCOT Ancillary Services Customer of any of its obligations under a long-term contract with the Transmission Provider.
421.7 Notification: If requested by the ERCOT IO, Tthe ERCOT Ancillary Services Customer and the Transmission Provider shall report to the ERCOT ISO the identity of the provider and user of ERCOT Ancillary Services and the non-price terms and conditions.
421.8 Initiating Service in the Absence of an Executed Service Agreement: If the Transmission Provider and a Transmission Customer requesting ERCOT Ancillary Services under this Part IV Tariff cannot agree on all the terms and conditions of the Service Agreement, the Transmission Provider shall file with the Commission, no later than thirty (30) days after the date the Transmission Customer ERCOT Ancillary Service Customer provides written notification directing the Transmission Provider to file, an unexecuted Service Agreement containing terms and conditions deemed appropriate by the Transmission Provider for such requested ERCOT Ancillary Services. The Transmission Provider shall commence providing Transmission Service subject to the Transmission Customer's ERCOT Ancillary Service Customer agreeing to (i) compensate the Transmission Provider at whatever rate the Commission ultimately determines to be just and reasonable, and (ii) comply with all other terms and conditions of this Tariff.
41.9 Qualified Scheduling Entity Service: Through December 31, 2001, CPL and WTU will assume the duties of QSE, in accordance with Section 4: Scheduling of the ERCOT Protocols, for themselves and for the customers that take full or partial requirements wholesale power supply service from CPL and WTU, respectively. CPL and WTU will assume such duties for these customers only until the earlier of the expiration of , unless the applicable service wholesale power supply agreement with CPL or WTU expires before or December 31, 2001. The basic charge for QSE service shall be $66.00 per day per customer.
CPL or WTU will also pass through to any party, for which it acts as QSE, charges imposed by the ERCOT IO for such ERCOT Ancillary Services as the party, or AEPSC acting on its behalf, purchases in the ERCOT Ancillary Service Market. In addition, CPL or WTU will pass through to such parties for which it acts as QSE a share of any other charges that the ERCOT IO bills to CPL or WTU, acting as QSE for such parties, including themselves. Such charges may include, without limitation, charges billed to CPL or WTU as QSE for Balancing Energy, Voltage Support, Black Start Service, Local Congestion, Replacement Reserve, Resource Imbalance, Uninstructed Resource, Out-of-Market-Capacity, Out-of-Market-Energy, Replacement Reserve Service, Under-Scheduled Charge, Replacement Reserve Uplift, Commercially Significant Constraint Congestion, Balancing Energy Neutrality Adjustment, and the ERCOT System Administration Fee. Such other charges shall be allocated among the Transmission Customers serving load in ERCOT, for which CPL and WTU act as QSE, based on the ratio of each such entity's adjusted metered load, pursuant to ERCOT protocols, for all ERCOT weekly billing periods that end within the previous calendar month, to the total adjusted metered load of all ERCOT load serving entities for which CPL and WTU act as QSE during such ERCOT weekly billing periods.
No later than November 1, 2001, CPL and WTU shall each notify in writing to each person for which it is then acting as QSE, whether and how CPL and WTU, or their affiliates, will provide QSE services following the restructuring of the ERCOT electric utility industry on January 1, 2002.
SCHEDULE 1
SYSTEM SCHEDULING, SYSTEM CONTROL AND DISPATCH SERVICE
This service is required to schedule the movement of power through, out of, within, or into a Control Area. This service can be provided only by the operator of the Control Area in which the transmission facilities used for transmission service are located. System Scheduling, System Control and Dispatch Service is to be provided directly by the Transmission Provider (if the Transmission Provider is the Control Area operator) or indirectly by the Transmission Provider making arrangements with the Control Area operator that performs this service for the Transmission Provider's Transmission System. The Transmission Customer must purchase this service from the Transmission Provider or the Control Area operator. The charges for System Scheduling, System Control and Dispatch Service are to be based on the rates set forth below. To the extent the Control Area operator performs this service for the Transmission Provider, charges to the Transmission Customer are to reflect only a pass-through of the costs charged to the Transmission Provider by that Control Area operator. A Transmission Customer taking service under this Tariff in ERCOT must obtain this service under the ERCOT Protocols.
Transmission Customers taking service under Part II or Part III may elect either Hourly Scheduling Service or Dynamic Scheduling Service.
Hourly Scheduling Service is a service that employs specific hourly schedules for the transmission of energy by coordinating the event among the affected Control Areas. The Transmission Customer provides a schedule, from midnight to midnight, containing up to 24 hourly values that signify the desired amount of energy to be transmitted from the supply host Control Area to a single load host Control Area. The service is different from Dynamic Scheduling Service in that the scheduled amount is not changed by a dynamic real-time signal, but is a fixed hourly amount. Hourly Scheduling Service includes set up, modification, confirmation, implementation, accounting and necessary reporting of the transaction, as well as the use of supporting hardware and software systems for control and tracking of schedules. Schedules shall be made in whole MW increments.
Dynamic Scheduling Service enables remote load regulation for a load, by effecting adjustments in schedules for energy transfers where the desired power level of the transaction is communicated by a real-time signal signifying an amount of generation, an amount of load, a regulation requirement, or a share of the output of a generator. The real-time signal indicating the dynamic schedule amount must be provided simultaneously to both the sending and receiving Control Areas for incorporation into their respective real-time control systems. Both sending and receiving Control Areas must integrate the signal and agree on the hourly energy transfers. The Transmission Customer is responsible for telemetry and signal processing costs. Any charges imposed by the Transmission Provider for telemetry and signal processing shall be stated in the Service Agreement. Dynamic Scheduling Service must be arranged with both the sending and receiving Control Areas. Dynamic Scheduling Service includes set up, modifications, communications between sending and receiving Control Areas, confirmation, accounting and necessary reporting of the transactions, as well as supporting hardware and software systems for control and tracking of schedules. Schedules shall be made in whole MW increments.
The rates for System Scheduling, System Control and Dispatch Service for transmission to a delivery point located in the AEP East Zone or the AEP West Zone (SPP) shall be up to:
AEP East Zone AEP West Zone (SPP)
Per MW-month $57.71 $30.00
Per MW-week $13.28 $ 6.90
Per MW-day $ 1.89 $ 0.99
Per MW-hour $ 0.08 $ 0.04
Such rates shall be applied to the amount of Reserved Capacity for transmission service under Part II and to the amount of monthly Network Load for transmission service under Part III.
SCHEDULE 2
SYSTEM REACTIVE SUPPLY AND VOLTAGE CONTROL FROM
GENERATION SOURCES SERVICE
In order to maintain transmission voltages on the Transmission Provider's transmission facilities within acceptable limits, generation facilities under the control of the control area operator are operated to produce (or absorb) reactive power. Thus, System Reactive Supply and Voltage Control from Generation Sources Service must be provided for each transaction on the Transmission Provider's transmission facilities. The amount of System Reactive Supply and Voltage Control from Generation Sources Service that must be supplied with respect to the Transmission Customer's transaction will be determined based on the reactive power support necessary to maintain transmission voltages within limits that are generally accepted in the region and consistently adhered to by the Transmission Provider.
System Reactive Supply and Voltage Control from Generation Sources Service is to be provided directly by the Transmission Provider (if the Transmission Provider is the Control Area operator) or indirectly by the Transmission Provider making arrangements with the Control Area operator that performs this service for the Transmission Provider's Transmission System. The Transmission Customer must purchase this service from the Transmission Provider or the Control Area operator. After the ERCOT Service Date, tThe Transmission Customer must obtain ERCOT Ancillary Services to serve load in ERCOT under the ERCOT Protocols, after the ERCOT Service Date. The charges for such service will be based on the rates set forth below. To the extent the Control Area operator performs this service for the Transmission Provider, charges to the Transmission Customer are to reflect only a pass-through of the costs charged to the Transmission Provider by the Control Area operator.
The rates for System Reactive Supply and Voltage Control from Generation Sources Service for transmission to a delivery point located in the AEP East Zone or the AEP West Zone (SPP) shall be up to:
AEP East Zone AEP West Zone (SPP)
Per MW-month $ 73.00 $48.05
Per MW-week $ 16.80 $11.06
Per MW-day
On-Peak $ 3.36 $ 2.21
Off-Peak $ 2.40 $ 1.58
Per MW-hour
On-Peak $ 0.21 $ 0.14
Off-Peak $ 0.10 $ 0.07
Such rates shall be applied to the amount of Reserved Capacity for transmission service under Part II and to the amount of monthly Network Load for transmission service under Part III. Although the Transmission Customer is required to take this ancillary service from the Transmission Provider, the Transmission Customer may reduce the charge for this service to the extent it can self supply reactive power.
The total charge in any day, pursuant to an hourly service reservation, shall not exceed the applicable rate for daily service specified above for the applicable Transmission Provider Control Area, times the highest amount of hourly service reserved in any hour during such day. In addition, the total charge in any week pursuant to a reservation for hourly or daily service shall not exceed the rate for weekly service specified above for the applicable Transmission Provider Control Area, times the highest amount of hourly or daily service reserved in any hour or day during such week.
The Off-Peak Period shall be all hours of Saturday, Sunday, New Year's Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, and Christmas Day and the hours between 11:00 p.m. and 7:00 a.m. local time on all other days. The On-Peak Period shall be all hours other than the hours in the Off-Peak Period.
SCHEDULE 3-A
SYSTEM REGULATION AND FREQUENCY RESPONSE SERVICE
System Regulation and Frequency Response Service is necessary to provide for the continuous balancing of resources (generation and interchange) with load and for maintaining scheduled Interconnection frequency at sixty cycles per second (60 Hz). System Regulation and Frequency Response Service is accomplished by committing on-line generation whose output is raised or lowered (predominantly through the use of automatic generating control equipment) as necessary to follow the moment-by-moment changes in load. The obligation to maintain this balance between resources and load lies with the Transmission Provider (or the Control Area operator that performs this function for the Transmission Provider). The Transmission Provider must offer this service when the transmission service is used to serve load within one of its Control Areas. The Transmission Customer must either purchase this service from the Transmission Provider or make alternative comparable arrangements to satisfy its System Regulation and Frequency Response Service obligation. The amount of and charges for System Regulation and Frequency Response Service shall be based on the cost of providing the service in the Control Area in which the Transmission Customer's load is (or portions of such load are) located. To the extent the Control Area operator performs this service for the Transmission Provider, charges to the Transmission Customer are to reflect only a pass-through of the costs charged to the Transmission Provider by that Control Area operator.
Transmission Customers serving load in any of the Transmission Provider's Control Areas that satisfactorily demonstrate that they will provide, or have made alternative comparable arrangements for the provision of, System Regulation and Frequency Response Service, consistent with applicable regional reliability standards, will not be charged for System Regulation and Frequency Response Service.
Other Transmission Customers will be charged for System Regulation and Frequency Response Service. The charges for System Regulation and Frequency Response Service will be based on the following Capacity Cost Per MW-month, load percentages and resulting rates for the applicable Transmission Provider Control Area:
AEP East Zone AEP West Zone (SPP) AEP West Zone (ERCOT)
Capacity Cost Per
MW-month $5,300.00 $2,609.00 $2,445.00
Load Percentage
Required 1.0% 1.2% 1.1%
Rates (Up to):
Per MW-month $ 53.00 $ 31.31 $ 26.90
Per MW-week $ 12.20 $ 7.20 $ 6.19
Per MW-day
On-Peak $ 2.44 $ 1.44 $ 1.24
Off-Peak $ 1.74 $ 1.02 $ 0.88
Per MW-hour
On-Peak $ 0.15 $ 0.09 $ 0.08
Off-Peak $ 0.07 $ 0.04 $ 0.04
Such rates shall be applied to the amount of Reserved Capacity for transmission service under Part II and to the amount of Monthly Network Load for transmission service under Part III. The total charge in any day, pursuant to an hourly service reservation, shall not exceed the applicable rate for daily service specified above for the applicable Transmission Provider Control Area, times the highest amount of hourly service reserved in any hour during such day. In addition, the total charge in any week pursuant to a reservation for hourly or daily service shall not exceed the rate for weekly service specified above for the applicable Transmission Provider Control Area, times the highest amount of hourly or daily service reserved in any hour or day during such week. A Transmission Customer purchasing System Regulation and Frequency Response Service for load in the SPP will be required to purchase an amount of reserved capacity equal to 1.2 percent of the Transmission Customer’s reserved capacity for point-to-point transmission service or 1.2 percent of the Transmission Customer’s network load responsibility for Network Integration Transmission Service. A Transmission Customer purchasing System Regulation and Frequency Response Service to serve load in ERCOT will be required to purchase an amount of reserved capacity equal to 1.1 percent of the Transmission Customer’s reserved capacity and 1.1 percent of the Transmission Customer’s network load responsibility for Network Integration Transmission Service. The billing determinants for these services shall be reduced by any portion of the applicable percentage purchase obligations that a Transmission Customer obtains from third parties or supplies itself.
The Off-Peak Period shall be all hours of Saturday, Sunday, New Year's Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, and Christmas Day and the hours between 11:00 p.m. and 7:00 a.m. local time on all other days. The On-Peak Period shall be all hours other than the hours in the Off-Peak Period.
SCHEDULE 3-B
SYSTEM LOAD FOLLOWING SERVICE
System Load Following Service consists of the supply of power and energy in response to hour-to-hour changes in the level of load being served and is available for transactions involving transfers between ERCOT and the SPP.
System Load Following Service provides power and energy to accommodate changes in load over an hour's time above that load served by hourly block transaction schedules. This may be done by integrating net load change over a predetermined period (less than one hour ) and ramping the generation providing the service to the level required to serve the load change. System Load Following Service differs from System Regulation and Frequency Response Service in that load following may not adequately accommodate moment-to-moment load variations. The capacity component of load following is the difference between the schedule and the maximum 15-minute integrated load during the hour. Thus, load-following capacity will not be greater than the difference between the minimum and maximum load during the hour. Energy transfers between Control Areas for load following must be arranged by either hourly or dynamic schedules. The Transmission Customer must either purchase this service from the Transmission Provider or make alternative comparable arrangements to satisfy its System Load Following Service obligation. The amount of and charges for System Load Following Service furnished by the Transmission Provider shall be based on the Control Area in which the Transmission Customer's load is (or portions of such load are) located.
System Load Following Service is offered in the AEP West Zone Control Areas. Transmission Customers serving load in the AEP West Zone Control Areas that satisfactorily demonstrate that they will provide, or have made alternative comparable arrangements for the provision of, System Load Following Service, consistent with applicable regional reliability standards, will not be charged for System Load Following Service.
If the Transmission Customer is purchasing System Regulation and Frequency Response Service from the Transmission Provider under Schedule 3-A or ERCOT Load Following Service under Schedule 13, the charges for System Load Following Service shall be waived.
Other Transmission Customers in one of the Transmission Provider's West Zone Control Areas for which Network Integration Transmission Service or Point-to-Point Transmission service is provided will be charged for System Load Following Service. The charges for System Load Following Service will be the product of the load following capacity and the rates for the applicable Transmission Provider's Control Area stated below:
AEP West Zone (SPP) AEP West Zone (ERCOT)
Rates (Up to):
Per MW-month $ 2,609.00 $ 2,445.00
Per MW-week $ 600.43 $ 562.68
Per MW-day
On-Peak $ 120.09 $ 112.54
Off-Peak $ 85.78 $ 80.38
Per MW-hour
On-Peak $ 7.51 $ 7.03
Off-Peak $ 3.57 $ 3.35
The total charge in any day, pursuant to an hourly service reservation, shall not exceed the applicable rate for daily service specified above for the applicable Transmission Provider Control Area, times the highest amount of hourly service reserved in any hour during such day. In addition, the total charge in any week pursuant to a reservation for hourly or daily service shall not exceed the rate for weekly service specified above for the applicable Transmission Provider Control Area, times the highest amount of hourly or daily service reserved in any hour or day during such week.
The Off-Peak Period shall be all hours of Saturday, Sunday, New Year's Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, and Christmas Day and the hours between 11:00 p.m. and 7:00 a.m. local time on all other days. The On-Peak Period shall be all hours other than the hours in the Off-Peak Period.
SCHEDULE 4
SYSTEM ENERGY IMBALANCE SERVICE (ECAR and SPP)
1.0 - General
System Energy Imbalance Service is provided when a difference occurs between the scheduled and the actual delivery of energy to a load located within a Control Area over a single hour. The Transmission Provider must offer this service when the transmission service is used to serve load within one of its Control Areas. The Transmission Customer must either purchase this service from the Transmission Provider or make alternative comparable arrangements to satisfy its Energy Imbalance Service obligation. To the extent the Control Area operator performs this service for the Transmission Provider, charges to the Transmission Customer are to reflect only a pass-through of the costs charged to the Transmission Provider by that Control Area operator.
The Transmission Provider shall establish a deviation band of +/- 1.5 percent (with a minimum of 2 MW) of the scheduled transaction to be applied hourly to any energy imbalance that occurs as a result of the Transmission Customer's scheduled transaction(s). Parties should attempt to eliminate energy imbalances within the limits of the deviation band within thirty (30) days after the Transmission Customer's receipt of notice of an energy imbalance or within such other reasonable period of time as is generally accepted in the region and consistently adhered to by the Transmission Provider. If an energy imbalance is not corrected within thirty (30) days following receipt of notice, or a reasonable period of time that is generally accepted in the region and consistently adhered to by the Transmission Provider, the Transmission Customer will compensate the Transmission Provider for such service in cash. Energy imbalances outside the deviation band will be subject to charges to be specified by the Transmission Provider. The charges for Energy Imbalance Service are set forth in Section 3 below.
2.0 - Definitions
For the purposes of this Schedule 4, the following definitions shall apply:
2.1 Off-Peak Period: All hours of Saturday, Sunday, New Year's Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, and Christmas Day and the hours between 11:00 p.m. and 7:00 a.m. local time on all other days.
2.2 On-Peak Period: All hours other than the hours in the Off-Peak Period.
2.3 System Firm Load Lambda: The Transmission Provider's incremental out-of-pocket cost to serve one additional megawatt for one hour over and above the actual firm load in the applicable Control Area of the Transmission Provider. The System Firm Load Lambda shall be calculated in the manner in which it is determined for reporting in the Transmission Provider's applicable annual FERC Form 714 report. Average monthly on-peak and off-peak System Firm Load Lambdas shall be calculated for each Control Area when necessary for application of this Schedule 4.
2.4 Allowable Unscheduled Power: A Transmission Customer's Allowable Unscheduled Power shall be equal to +/- 1.5% (with a minimum of 2 MW) of the hourly energy scheduled for transmission.
2.5 Excess Energy Imbalance: The amount of Unscheduled Receipt in excess of the Allowable Unscheduled Power in any hour shall be accounted for as Excess Energy Imbalance.
2.6 Dump Energy: The amount of Unscheduled Delivery in excess of the Allowable Unscheduled Power in any hour shall be accounted for as Dump Energy.
2.7 Total Load: With respect to a Transmission Customer that is a Receiving Party, Total Load in any hour shall be the load measured at the Customer's delivery points, plus the amount of energy, if any, scheduled by the Transmission Customer for receipt by the Transmission Provider at such point in such hour for transmission to others less any energy purchased by the Transmission Customer from any of the AEP Operating Companies in such hour.
With respect to a Transmission Customer that is a Delivering Party, Total Load in any hour shall be the total amount of energy scheduled by the Transmission Customer to be delivered by the Transmission Provider at all of the Customer's delivery points, less any energy purchased by the Customer from any of the AEP Operating Companies in such hour.
2.8 Total Supply: With respect to a Transmission Customer that is a Receiving Party, Total Supply in any hour shall be the total of all amounts of energy scheduled by the Transmission Customer for transmission by the Transmission Provider to the Transmission Customer's delivery points, less average system losses. Average losses will be calculated in accordance with Section 15.7 or 28.5 of this Tariff, as applicable, and the Service Agreement.
With respect to a Transmission Customer that is a Delivering Party, Total Supply in any hour shall be the actual energy received each hour at the receipt points, as measured by suitable metering equipment, owned, operated or approved by the Transmission Provider.
2.9 Unscheduled Energy Account: The Transmission Provider shall keep a record of Unscheduled Deliveries, Unscheduled Receipts, and the disposition of such energy in sufficient detail as shall be needed to effect settlements under this Schedule. The record so kept for each Transmission Customer shall be known as the Customer's Unscheduled Energy Account.
2.10 Unscheduled Delivery: An Unscheduled Delivery shall be the amount by which a Transmission Customer's Total Supply in any hour exceeds its Total Load.
2.11 Unscheduled Receipt: An Unscheduled Receipt shall be the amount by which a Transmission Customer's Total Load in any hour exceeds its Total Supply.
Section 3.0 - Energy Accounting and Charges
3.1 Unscheduled Energy Accounting: Unless otherwise agreed by the Transmission Provider and the Transmission Customer, the Transmission Provider will record in the Transmission Customer's Unscheduled Energy Account each month the total of the hourly Unscheduled Receipts and Deliveries by the Customer separately for the On-Peak Period and Off-Peak Period, and will determine a net Unscheduled Receipt or Delivery, rounded to the nearest whole MWH, for each period.
It shall be the Transmission Customer's responsibility to schedule with the Transmission Provider's control center the return in-kind of Unscheduled Deliveries during like time periods within 30 days after notice of such energy imbalance or during the next or second following billing month, if later. Unscheduled Deliveries not so scheduled by the Customer will be eliminated from the Unscheduled Energy Account and a credit for such deliveries will be applied to the Transmission Customer's billing in the second following month. The credit will be equal to the product of the Unscheduled Delivery not scheduled for return and the applicable average System Firm Load Lambda for On-Peak Period and Off-Peak Period, respectively, during the month when such energy was delivered by the Transmission Customer.
Likewise, it shall be the Transmission Provider's responsibility to schedule with the Transmission Customer for the return in-kind by the Transmission Customer of Unscheduled Receipts, during like time periods of the next or second following month. Unscheduled Receipts not so returned will be eliminated from the Unscheduled Energy Account when statements for the second following month are prepared. The unreturned amounts will be billed to the Transmission Customer based on the applicable average System Firm Load Lambda energy cost for On-Peak and Off-Peak Periods, respectively, during the month when such energy was received by the Transmission Customer.
If in any hour the unscheduled energy flow as determined above exceeds the Allowable Unscheduled Power, the return in-kind provisions of this subsection shall not apply to the excess energy; rather, in such hour, the provisions of subsection 3.2, Excess Energy Imbalance, shall apply to excess Unscheduled Receipts and the provisions of subsection 3.3, Dump Energy, shall apply to excess Unscheduled Deliveries.
3.2 Excess Energy Imbalance: In any hour in which an Unscheduled Receipt exceeds the Allowable Unscheduled Power, the excess Unscheduled Receipt for such hour will be billed as Excess Energy Imbalance. The Transmission Customer shall pay a charge equal to the Excess Energy Imbalance in any hour times the greater of: (i) $100/MWH; or (ii) 110% of the incremental cost of energy produced or purchased in such hour in the applicable zone.
3.3 Dump Energy: Monthly billing credits for Dump Energy, given by the Transmission Provider to the Transmission Customer, shall equal the product of the applicable hourly System Firm Load Lambda and any Dump Energy supplied by the Transmission Customer in that hour.
SCHEDULE 4-A
RETAIL ENERGY IMBALANCE SERVICE
1. Applicability
This schedule is applicable to settlements for energy imbalances incurred by Transmission Customers that are or that supply electricity to retail consumers who have supplier choice pursuant to a state authorized retail competitive access program (referred to herein as "Retail Access Customers"). Service under this Schedule 4-A is offered in any of the areas served by the AEP Companies until service is available in such area(s) from a regional transmission organization.
2. General
Energy Imbalance Service is provided when a difference occurs between the scheduled and the actual delivery of energy to a load located within a Control Area in any hour. The Transmission Provider must offer Energy Imbalance Service when the transmission service is used to serve load within its Control Area. The Transmission Customer must either purchase Energy Imbalance Service from the Transmission Provider or make alternative comparable arrangements to satisfy its Energy Imbalance Service obligation. To the extent the Control Area operator performs this service for the Transmission Provider, charges to the Transmission Customer are to reflect only a pass-through of the costs charged to the Transmission Provider by that Control Area operator. Settlements under this Schedule 4-A will be made in cash. The charges and credits for Retail Energy Imbalance Service are set forth below.
3. Definitions
For the purposes of this Schedule 4-A, the following definitions shall apply:
3.1 Hourly Market Price: The Hourly Market Price for purposes of settlements under this Schedule 4-A shall be the market price in each hour for the applicable AEP System Control Area or Zone. The Hourly Market Price for any Control Area or Zone will be based on a consistently available electricity price indicator for such Control Area or Zone. Any such market price indicator shall be a regularly published factor recognized in the industry as a reliable measure of the hourly wholesale price of electricity in such region, accepted by the Commission pursuant to a filing by AEP. The Hourly Market Price for each AEP Control Area or Zone shall be as follows: East Zone (not available), West Zone-SPP (not available), West Zone-ERCOT (not available). If no suitable market price indicator is available for use in any AEP System Control Area or Zone, and Energy Imbalance Service is not available through any regional transmission organization covering such area, then for settlement purposes hereunder a proxy for the Hourly Market Price shall be determined as follows:
The greater of the following incremental cost measures experienced by the AEP Companies in each hour for the applicable Control Area or Zone, expressed in $/MWh: (i) the incremental cost of operating the last generating unit dispatched (including fuel, emissions allowance and variable operating expenses), (ii) the incremental cost of energy purchased by the AEP Companies, and (iii) the MWH weighted average price charged by the AEP Companies for hourly electricity sold during the hour. In addition, if the AEP Companies must curtail a power sale to provide energy for Energy Imbalance Service hereunder in any hour, then any costs incurred thereby for liquidated damages, and any curtailment-related penalties, shall be allocated to Transmission Customers that have load exceeding their scheduled deliveries in such Control Area or Zone, through an additional $/MWh charge for such hours in such Control Area or Zone as will be sufficient to recover the portion of such additional cost that is attributable to such Energy Imbalance Service.
3.2 Decremental Cost: Decremental Cost in any of the AEP Companies' Control Areas or Zones in any hour shall be equal to the sum of the fuel, emission allowance and variable operating expenses that are avoided in reducing output on the last generating unit dispatched for such Control Area or Zone in such hour. In addition, if the AEP Companies would have to shut down any generating unit(s) that would not have been shut down but for the requirement to provide Energy Imbalance Service, then the cost incurred to shut-down and restart such unit(s), or the cost of actions taken in lieu of such shut down, shall be allocated to Transmission Customers that have scheduled deliveries exceeding their loads in such Control Area or Zone, through an additional $/MWh charge for such hours in such control area or Zone as will be sufficient to recover the portion of such cost that is attributable to such Energy Imbalance Service.
3.3 Hourly Load: The Hourly Load of a Retail Access Customer, for application of this Schedule 4-A, shall mean the energy determined to have been required each hour to supply the load at the Customer's Delivery Point(s) (measured and/or estimated based on load profile data), plus delivery losses (transmission losses as specified in the Tariff and distribution losses as specified in the Service Agreement) and a ratable share of the difference each hour between the energy delivered to all customers (retail and requirements wholesale) in a retail rate area (including deliveries to the Transmission Provider's Native Load customers) and the sum of the delivery point loads and losses determined separately for each customer (including the Transmission Provider's Native Load customers). Hourly Load will be determined in whole MW. Fractional MW amounts of Hourly Load will be carried over each hour until such fractional amounts accumulate to a whole MW.
3.4 Hourly Supply: The Hourly Supply of a Retail Access Customer, for application of this Schedule 4-A, shall mean the energy scheduled by the Retail Access Customer to be received for transmission by the Transmission Provider (in whole MW per hour) under all schedules enacted for delivery to the Transmission Customer's Hourly Load.
3.5 Over-Scheduled Energy: Over-Scheduled Energy shall be the amount each hour, if any, by which a Retail Access Customer's Hourly Supply exceeds its Hourly Load.
3.6 Under-Scheduled Energy: Under-Scheduled Energy shall be the amount each hour, if any, by which a Retail Access Customer's Hourly Load exceeds its Hourly Supply .
4. Energy Imbalance Settlements
4.1 Recommended Schedules for Retail Access Loads: The AEP Companies will make hourly load profile information available to Retail Access Customers for all retail customer classes identified for load profiling pursuant to the requirements of the state retail access program for the applicable retail rate area. The AEP Companies will develop the capability to produce day-ahead hourly retail load forecasts and recommended schedules (referred to collectively herein as "Recommended Schedules") for Retail Access Customers, and make such Recommended Schedules available at least two (2) hours prior to the day-ahead scheduling deadline. If for any reason the AEP Companies are unable to provide Recommended Schedules for any Retail Access Customer(s), the provisions of section 4.3 shall apply, otherwise Retail Energy Imbalance charges and credits shall be as specified in section 4.2 below.
4.2 Charges and Credits for Retail Energy Imbalance: Charges and credits for Retail Energy Imbalance will vary depending on whether or not the Retail Access Customer uses the Recommended Schedule, as follows:
4.2.1 Conforming Schedules: A Retail Access Customer that submits day-ahead schedules that conform to the Recommended Schedule ("Conforming Schedules") will be charged for hourly Under-Scheduled Energy based on 100% of the Hourly Market Price (plus charges for curtailment of sales, if any), and credited for hourly Over-Scheduled Energy based on 100% of the Decremental Cost (less charges related to unit shut down, if any).
4.2.2 Non-Conforming Schedules: The Transmission Provider reserves the right to reject any schedule that does not conform to the Recommended Schedule ("Non-conforming Schedule"); provided, however, that if a retail provider shall re-submit a Non-conforming Schedule the Transmission Provider will accept such schedule, if it otherwise meets standard scheduling requirements. In such cases; however, any Under-Scheduled Energy that results from such Non-conforming Schedule, that would not have occurred under a Conforming Schedule, will be charged at the greater of $100/MWh or 110% of the Hourly Market Price (plus charges for curtailment of sales, if any), and any Over-Scheduled Energy that results from such Non-conforming Schedule, that would not have occurred under a Conforming Schedule, will be credited based on 90% of the Decremental Cost for such hour (less charges related to unit shut down, if any). Charges and credits, respectively, for Under-Scheduled and Over-Scheduled Energy resulting from a Non-conforming Schedule that also would have occurred under a Conforming Schedule will be as specified in section 4.2.1 above. The Transmission Provider shall obtain no liability in accepting any Non-conforming Schedule, and the prices described herein for additional Energy Imbalance resulting from a Non-conforming Schedule shall apply whether or not the Transmission Provider rejects a Non-conforming Schedule when first submitted.
4.3 Charges and Credits If Recommended Schedules Are Not Available: If the AEP Companies are unable to provide day-ahead Recommended Schedules at the start of a retail access program they will do so at the earliest practicable date. For such time or under such circumstances as the Recommended Schedules can not be provided, the Transmission Provider will allow an Energy Imbalance Deviation Band of +/-5% of the Retail Access Customer's Hourly Load, with a minimum of 2 MW per hour. Hourly Retail Energy Imbalances within the Deviation Band will be priced as specified in section 4.2.1 for Conforming Schedules. Hourly Retail Energy Imbalances outside the Deviation Band will be priced as specified in section 4.2.2 for Non-conforming Schedules.
SCHEDULE 5
SYSTEM OPERATING RESERVE - SPINNING RESERVE SERVICE
(ECAR and SPP) OR RESPONSIVE RESERVE SERVICE (ERCOT)
System Spinning Reserve Service (ECAR and SPP) or Responsive Reserve Service (ERCOT) is needed to serve load immediately in the event of a system contingency. Spinning Reserve Service (ECAR and SPP) may be provided by generating units that are on-line and loaded at less than maximum output. Responsive Reserve Service (ERCOT) may be provided by unloaded on-line generating units that are equipped with frequency sensitive generator controls, interruptible load controlled by high set underfrequency relays, hydroelectric generators operating in fast synchronous condenser mode, and HVDC Facilities response The Transmission Provider must offer this service when the transmission service is used to serve load within one of its Control Areas. The Transmission Customer must either purchase this service from the Transmission Provider or make alternative comparable arrangements to satisfy its System Spinning Reserve Service. or Responsive Reserve Service obligation.
The amount of and charges for Spinning Reserve Service and Responsive Reserve Service shall be based on the cost of providing the service in the Control Area in which the Transmission Customer's load is (or portions of such load are) located. To the extent the Control Area operator performs this service for the Transmission Provider, charges to the Transmission Customer are to reflect only a pass-through of the costs charged to the Transmission Provider by that Control Area operator.
Transmission Customers serving load in the AEP East Zone or in the AEP West Zone SPP Control Area, as the case may be, that satisfactorily demonstrate that they will provide, or have made alternative comparable arrangements for the provision of, Spinning Reserve Service, consistent with applicable regional reliability standards, will not be charged for Spinning Reserve Service. Transmission Customers serving load in the AEP West Zone ERCOT Control Area that satisfactorily demonstrate that they will provide, or have made alternative comparable arrangements for the provision of, Responsive Reserve Service, consistent with applicable regional reliability standards, will not be charged for Responsive Reserve Service.
Other Transmission Customers will be charged for Spinning Reserve Service or Responsive Reserve Service, as applicable. The charges for Spinning Reserve Service and Responsive Reserve Service will be based on the following Capacity Cost Per MW-month, load percentages and resulting rates for the applicable Transmission Provider Control Area:
AEP East Zone AEP West Zone (SPP) AEP West
Zone (ERCOT)
Capacity Cost Per
MW-month $5,300.00 $3,482.00 $3,121.00
Load Percentage
Required 1.5% 2.1% 5.9%
Rates (Up to):
Per MW-month $ 79.50 $ 73.12 $ 184.14
Per MW-week $ 18.30 $ 16.83 $ 42.38
Per MW-day
On-Peak $ 3.66 $ 3.37 $ 8.48
Off-Peak $ 2.61 $ 2.40 $ 6.05
Per MW-hour
On-Peak $ 0.23 $ 0.21 $ 0.53
Off-Peak $ 0.11 $ 0.10 $ 0.25
Such rates shall be applied to the amount of Reserved Capacity for transmission service under Part II and to the amount of monthly Network Load for transmission service under Part III. A Transmission Customer purchasing Spinning Reserve Service (SPP) will be required to purchase an amount of reserved capacity equal to 2.1 percent of the Transmission Customer’s reserved capacity for Point-to-Point Transmission Service or 2.1 percent of the Transmission Customer’s Network Load for Network Integration Transmission Service. A Transmission Customer purchasing Responsive Reserve Service (ERCOT) will be required to purchase an amount of reserved capacity equal to 5.9 percent of the Transmission Customer’s reserved capacity for Point-to-Point Transmission Service or 5.9 percent of the Transmission Customer’s Network Load for Network Integration Transmission Service. The billing determinants for this service shall be reduced by any portion of the applicable percentage purchase obligation that a Transmission Customer obtains from third parties or supplies itself.
The total charge in any day, pursuant to an hourly service reservation, shall not exceed the applicable rate for daily service specified above for the applicable Transmission Provider Control Area, times the highest amount of hourly service reserved in any hour during such day. In addition, the total charge in any week pursuant to a reservation for hourly or daily service shall not exceed the rate for weekly service specified above for the applicable Transmission Provider Control Area, times the highest amount of hourly or daily service reserved in any hour or day during such week.
The Off-Peak Period shall be all hours of Saturday, Sunday, New Year's Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, and Christmas Day and the hours between 11:00 p.m. and 7:00 a.m. local time on all other days. The On-Peak Period shall be all hours other than the hours in the Off-Peak Period.
SCHEDULE 6
SYSTEM OPERATING RESERVE --
SUPPLEMENTAL RESERVE SERVICE (ECAR and SPP)
OR SPINNING RESERVE SERVICE (ERCOT)
System Supplemental Reserve Service (ECAR and SPP) or Spinning Reserve Service (ERCOT) is needed to serve load in the event of a system contingency; however, it is not available immediately to serve load but rather within a short period of time. Supplemental Reserve Service (ECAR and SPP) may be provided by generating units that are on-line but unloaded, by quick-start generation or by interruptible load. Spinning Reserve Service (ERCOT) may be provided by operating resources not used in meeting Responsive Reserve obligations and the capability of HVDC Facilities that can be utilized within the permitted time for applying Supplemental ReserveThe Transmission Provider must offer this service when the transmission service is used to serve load within one of its Control Areas. The Transmission Customer must either purchase this service from the Transmission Provider or make alternative comparable arrangements to satisfy its Supplemental Reserve Service or Spinning Reserve Service obligation.
The amount of and charges for Supplemental Reserve Service orSpinning Reserve Service shall be based on the Control Area in which the Transmission Customer's load is (or portions of such load are) located. To the extent the Control Area operator performs this service for the Transmission Provider, charges to the Transmission Customer are to reflect only a pass-through of the costs charged to the Transmission Provider by that Control Area operator.
Transmission Customers serving load in the AEP East Zone or in the AEP West Zone SPP Control Area, as the case may be, that satisfactorily demonstrate that they will provide, or have made alternative comparable arrangements for the provision of, Supplemental Reserve Service, consistent with applicable regional reliability standards, will not be charged for Supplemental Reserve Service. Transmission Customers serving load in the AEP West Zone ERCOT Control Area that satisfactorily demonstrate that they will provide, or have made alternative comparable arrangements for the provision of, Spinning Reserve Service, consistent with applicable regional reliability standards, will not be charged for Spinning Reserve Service.
Other Transmission Customers will be charged for Supplemental Reserve Service or Spinning Reserve Service, as applicable. The charges for Supplemental Reserve Service and Spinning Reserve Service will be based on the following Capacity Cost Per MW-month, load percentages and resulting rates for the applicable Transmission Provider Control Area:
AEP East Zone AEP West Zone (SPP) AEP West Zone (ERCOT)
Capacity Cost Per
MW-month $5,300.00 $3,467.00 $3,121.00
Load Percentage
Required 1.5% 2.1% (Up to) 5.9%
Rates (Up to):
Per MW-month $ 79.50 $ 72.80 $ 184.14
Per MW-week $ 18.30 $ 16.75 $ 42.38
Per MW-day
On-Peak $ 3.66 $ 3.35 $ 8.48
Off-Peak $ 2.61 $ 2.39 $ 6.05
Per MW-hour
On-Peak $ 0.23 $ 0.21 $ 0.53
Off-Peak $ 0.11 $ 0.10 $ 0.25
Such rates shall be applied to the amount of Reserved Capacity for transmission service under Part II and to the amount of monthly Network Load for transmission service under Part III. A Transmission Customer purchasing Supplemental Reserve Service (SPP) will be required to purchase an amount of reserved capacity equal to 2.1 percent of the Transmission Customer’s reserved capacity for Point-to-Point Transmission Service or 2.1 percent of the Transmission Customer’s Network Load for Network Integration Transmission Service. A Transmission Customer purchasing Spinning Reserve Service (ERCOT) will be required to purchase an amount of reserved capacity equal to up to 5.9 percent of the Transmission Customer’s reserved capacity for Point-to-Point Transmission Service or up to 5.9 percent of the Transmission Customer’s Network Load for Network Integration Transmission Service when ERCOT declares a weather alert or when the ERCOT ISO declares an emergency. The billing determinants for this service shall be reduced by any portion of the applicable percentage purchase obligation that a Transmission Customer obtains from third parties or supplies itself.
The total charge in any day, pursuant to an hourly service reservation, shall not exceed the applicable rate for daily service specified above for the applicable Transmission Provider Control Area, times the highest amount of hourly service reserved in any hour during such day. In addition, the total charge in any week pursuant to a reservation for hourly or daily service shall not exceed the rate for weekly service specified above for the applicable Transmission Provider Control Area, times the highest amount of hourly or daily service reserved in any hour or day during such week.
The Off-Peak Period shall be all hours of Saturday, Sunday, New Year's Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, and Christmas Day and the hours between 11:00 p.m. and 7:00 a.m. local time on all other days. The On-Peak Period shall be all hours other than the hours in the Off-Peak Period.
SCHEDULE 7
LONG-TERM FIRM AND SHORT-TERM FIRM
POINT-TO-POINT TRANSMISSION SERVICE
The Transmission Customer shall compensate the Transmission Provider each month for Reserved Capacity. The rates for Long-Term Firm and Short-Term Firm Point-to-Point Transmission Service to points of delivery located in the AEP East Zone or the AEP West Zone shall be:
AEP East Zone AEP West Zone
Per MW-month $ 1,420.00 $ 1,050.00
Per MW-week $ 326.79 $ 241.64
Per MW-day
On-Peak $ 65.36 $ 48.33
Off-Peak $ 46.68 $ 34.52
The total demand charge in any week, pursuant to a reservation for Daily delivery, shall not exceed the weekly rate specified above times the highest amount in megawatts of Reserved Capacity in any day during such week.
Discounts: Three principal requirements apply to discounts for transmission service as follows (1) any offer of a discount made by the Transmission Provider must be announced to all Eligible Customers solely by posting on the OASIS, (2) any customer-initiated requests for discounts (including requests for use by one's wholesale merchant or an affiliate's use) must occur solely by posting on the OASIS, and (3) once a discount is negotiated, details must be immediately posted on the OASIS. For any discount agreed upon for service on a path, from point(s) of receipt to point(s) of delivery, the Transmission Provider must offer the same discounted transmission service rate for the same time period to all Eligible Customers on all unconstrained transmission paths that go to the same point(s) of delivery on the Transmission System.
An Load Serving Entity Eligible Customer that takes ERCOT Regional Transmission Service under Part IV of this Tariff and also takes Transmission Service under Part II of this the SPP Tariff to import power and energy into ERCOT power and energy Planned Rresources or Unplanned Resources to serve its Native Load cCustomers in ERCOT shall have its facilities charges under this Schedule 7 Attachment T of the SPP Tariff reduced by 45.27% for transmission through the AEP West Zone.
A Transmission Customer that takes transmission service under Part II of this Tariff in conjunction with the use of the SPP Tariff to transmit energy from a Point of Receipt located in ERCOT to a Point of Delivery located outside of ERCOT, except to a Point of Delivery located in the AEP East Zone, shall in addition to charges due under the SPP Tariff pay facilities charges under this Schedule 7 that are reduced by 54.73%.
For purposes of this Schedule 7, the Off-Peak Period shall be Saturdays, Sundays, New Year's Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, and Christmas Day and the On-Peak Period shall be all days that are not in the Off-Peak Period.
SCHEDULE 8
NON-FIRM POINT-TO-POINT TRANSMISSION SERVICE
The Transmission Customer shall compensate the Transmission Provider for Non-Firm Point-To-Point Transmission Service up to the charges set forth below. The rates for Non-Firm Point-to-Point Transmission Service to points of delivery located in the AEP East Zone or the AEP West Zone shall be up to:
AEP East Zone AEP West Zone
Per MW-month $ 1,420.00 $ 1,050.00
Per MW-week (a) $ 326.79 $ 241.64
Per MW-day
On-Peak $ 65.36 $ 48.33
Off-Peak $ 46.68 $ 34.52
Per MW-hour
On-Peak $ 4.09 $ 3.02
Off-Peak $ 1.95 $ 1.44
The total demand charge in any week, pursuant to a reservation for Daily delivery, shall not exceed the weekly rate specified above times the highest amount in megawatts of Reserved Capacity in any day during such week.
The total demand charge in any day, pursuant to a reservation for Hourly delivery, shall not exceed the applicable daily rate specified above times the highest amount in megawatts of Reserved Capacity in any hour during such day. In addition, the total demand charge in any week, pursuant to a reservation for Hourly or Daily delivery, shall not exceed the weekly rate specified above times the highest amount in megawatts of Reserved Capacity in any hour during such week.
Discounts: Three principal requirements apply to discounts for transmission service as follows (1) any offer of a discount made by the Transmission Provider must be announced to all Eligible Customers solely by posting on the OASIS, (2) any customer-initiated requests for discounts (including requests for use by one's wholesale merchant or an affiliate's use) must occur solely by posting on the OASIS, and (3) once a discount is negotiated, details must be immediately posted on the OASIS. For any discount agreed upon for service on a path, from point(s) of receipt to point(s) of delivery, the Transmission Provider must offer the same discounted transmission service rate for the same time period to all Eligible Customers on all unconstrained transmission paths that go to the same point(s) of delivery on the Transmission System.
An Load Serving Entity Eligible Customer that takes ERCOT Regional Transmission Service under Part IV of this Tariff and also takes Transmission Service under Part II of this the SPP Tariff to import power and energy into ERCOT power and energy Planned Rresources or Unplanned Resources to serve its Native Load Ccustomers in ERCOT shall have its facilities charges under this Schedule 8 Attachment T of the SPP Tariff reduced by 45.27% for transmission through the AEP West Zone.
A Transmission Customer that takes transmission service under Part II of this Tariff in conjunction with the use of the SPP Tariff to transmit energy from a Point of Receipt located in ERCOT to a Point of Delivery located outside of ERCOT, except to a Point of Delivery located in the AEP East Zone, shall in addition to charges due under the SPP Tariff pay facilities charges under this Schedule 8 that are reduced by 54.73%.
For purposes of this Schedule 8, the Off-Peak Period shall be all hours of Saturday, Sunday, New Year's Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, and Christmas Day and the hours between 11:00 p.m. and 7:00 a.m. local time on all other days and the On-Peak Period shall be all hours that are not in the Off-Peak Period.
SCHEDULE 9
ERCOT RESPONSIVE RESERVE SERVICEREGULATION SERVICE-UP
Under this schedule CPL and WTU will provide generating capacity service that an ERCOT Ancillary Services Customer may use to satisfy its Regulation Service-Up obligation to the ERCOT IO. The ERCOT IO can deploy the generating capacity for the purpose of continuously balancing generation and load within the ERCOT System in response to a decrease in ERCOT System frequency to maintain the target ERCOT frequency within predetermined limits according to the ERCOT operating guides. Responsive Reserve consists of the daily operating reserves that are intended to help restore the frequency of the interconnected transmission system within the first few minutes of an event that causes a significant deviation from the standard frequency. Responsive Reserve may be provided by unloaded generation facilities that are on line, interruptible load controlled by high set under-frequency relays, or from HVDC Facility response that arrests frequency decay.
This includes those operating reserves that are intended to help the interconnection restore the frequency within the first few minutes following a frequency disturbance, including certain spinning reserves on generating units that are equipped with frequency sensitive governor controls, loads controlled by high- set under frequency relays, hydroelectric generators operating in fast synchronous condenser mode, and HVDC Facilities response.
The rates charges for capacity used to provide Regulation Service-Up to an ERCOT Ancillary Services Customer service shall be negotiated by CPL and WTU and the ERCOT Ancillary Service Customer, but shall not be more than the maximum rates or less than the minimum rates set forth below, applied to the amount of Responsive Reserve Regulation Service-Up provided to the ERCOT IO on behalf of the Customerpurchased:
(1) For Yearly delivery, not more than $43,594.07/MW or less than $5,960.00/MW per year, payable in equal monthly installments.
(21) For Monthly delivery, not more than $3,67932.8407/MW or less than $496.67/MW per month.
(32) For Weekly delivery, not more than $84938.3502/MW or less than $114.62/MW per week.
(43) For Daily delivery, not more than $12119.7629/MW or less than $16.37/MW per day.
(4) For Hourly delivery, not more than $5.05/MW or less than $.68/MW per hour.
Notwithstanding the above, the floor price for transactions up to and including one year in length will be no less than CPL's and WTU's short-run marginal cost determined in accordance with Texas Public Utility Regulatory Act § 2.001(c); the floor price for transactions lasting longer than one year will be no less than CPL's and WTU's long-run marginal cost determined in accordance with Texas Public Utility Regulatory Act § 2.001(c). Should the floor price as calculated per the description above exceed the ceiling price, the price charged will be the ceiling price.
SCHEDULE 10
ERCOT SPINNING RESERVE SERVICEREGULATION SERVICE-DOWN
Spinning reserve consists of the net generation capability on line that is not loaded, but could be loaded, and capability of an HVDC Facility that can be utilized in a specified time.
This includes those operating reserves not used in meeting responsive reserve obligation, which must be provided or obtained by the buyer to back up non-firm transactions such as Economy A energy transactions. Spinning reserve consists of the net generation capability on line that is not loaded, but could be loaded, and capability of an HVDC Facility that can be utilized in a specified time
. Under this Schedule CPL and WTU will provide generating capacity service that an ERCOT Ancillary Services Customer may use to satisfy its Regulation Service-Down obligation to the ERCOT IO. The ERCOT IO can deploy the generating capacity for the purpose of continuously balancing generation and load within the ERCOT System in response to an increase in ERCOT System frequency to maintain the target ERCOT frequency within predetermined limits according to the ERCOT operating guides.
The rates charges for capacity used to provide Regulation Service-Down to an ERCOT Ancillary Services CustomerSpinning Reserve Service shall be negotiated by CPL and WTU and the ERCOT Ancillary Services Customer, but shall not be more than the maximum rates or less than the minimum rates set forth below, applied to the amount of Spinning Reserve Regulation Service-Down provided to the ERCOT IO on behalf of the Customerpurchased:
(1) For Yearly delivery, not more than $43,594.07/MW or less than $5,960.00/MW per year, payable in equal monthly installments.
(21) For Monthly delivery, not more than $3,67932.0784/MW or less than $496.67/MW per month.
(32) For Weekly delivery, not more than $84938.3502/MW or less than $114.62/MW per week.
(43) For Daily delivery, not more than $12119.7629/MW or less than $16.37/MW per day.
(4) For Hourly delivery, not more than $5.05/MW or less than $.68/MW per hour.
Notwithstanding the above, the floor price for transactions up to and including one year in length will be no less than CPL's and WTU's short-run marginal cost determined in accordance with Texas Public Utility Regulatory Act § 2.001(c); the floor price for transactions lasting longer than one year will be no less than CPL's and WTU's long-run marginal cost determined in accordance with Texas Public Utility Regulatory Act § 2.001(c). Should the floor price as calculated per the description above exceed the ceiling price, the price charged will be the ceiling price.
SCHEDULE 11
ERCOT STATIC RESPONSIVE RESERVES SCHEDULING SERVICE
Static scheduling is a service that establishes specific hourly schedules for the transmission of energy by coordinating the event among the affected Control Areas. ERCOT Static Scheduling Service reflects the typical transaction where the ERCOT Ancillary Services Customer provides a schedule, from midnight to midnight, containing up to 24 hourly values that signify the desired power level to be transmitted from the supply host Control Area to a single load host Control Area. The service is different from dynamic scheduling in that the scheduled amount is not changed by a dynamic real-time signal, but is a fixed hourly amount. ERCOT Static Scheduling Service includes set up, modification, confirmation, implementation, accounting and necessary reporting of the transaction, as well as the use of supporting hardware and software systems for control and tracking of schedules. Schedules shall be made in increments of 1 MW.
The rates for ERCOT Static Scheduling Service shall be negotiated by the Transmission Provider and the ERCOT Ancillary Services Customer, but shall not be more than $66.00 per transaction per day.Under this Schedule CPL and WTU will provide generating capacity service that an ERCOT Ancillary Services Customer may use to satisfy its Responsive Reserves Service obligation to the ERCOT IO. The ERCOT IO can deploy the generating capacity to restore the frequency of the ERCOT System within the first few minutes of an event that causes a significant deviation from the standard frequency or in response to loss-of-resource contingencies on the ERCOT System.
The charges for capacity used to provide Responsive Reserve Service shall not be more than the maximum rates or less than the minimum rates set forth below, applied to the amount of Responsive Reserve Service provided to the ERCOT IO on behalf of the Customer:
(1) For Monthly delivery, not more than $3,632.84/MW or less than $496.67/MW per month.
(2) For Weekly delivery, not more than $838.35/MW or less than $114.62/MW per week.
(3) For Daily delivery, not more than $119.76/MW or less than $16.37/MW per day.
SCHEDULE 12
ERCOT DYNAMIC SCHEDULING SERVICENON-SPINNING RESERVE SERVICE
Dynamic scheduling is a service that may be used for load or generation that is connected to the transmission system of one control area to access bulk power and ancillary services from another control area.This is a service that provides, effects and adjusts schedules for energy transfers where the desired power level of the transaction is communicated by a real-time signal signifying an amount of generation, an amount of load, a regulation requirement, or a share of the output of a jointly-owned generator. The real-time signal indicating the dynamic schedule amount must be provided simultaneously to both the sending and receiving Control Areas for incorporation into their respective real-time control systems. Both sending and receiving Control Areas must integrate the signal and agree on the hourly energy transfers. ERCOT Ancillary Services Customer is responsible for providing telemetry and signal processing at the customer end. The Control Areas are responsible for telemetry and signal processing between Control Areas. ERCOT Dynamic Scheduling Service must be arranged with both the sending and receiving Control Areas. ERCOT Dynamic Scheduling Service includes set up, modifications, communications between sending and receiving Control Areas, confirmation, accounting and necessary reporting of the transaction, as well as supporting hardware and software systems for control and tracking of schedules. The unit of schedule provided in this service is 1 MW.Under this Schedule CPL and WTU will provide generating capacity service that an ERCOT Ancillary Services Customer may use to satisfy its Non-Spinning Reserve Service obligation to the ERCOT IO. The ERCOT IO can deploy the generating capacity in response to loss-of-Resource contingencies on the ERCOT system.
The rates charges for capacity used to provide Non-Spinning Reserve Service ERCOT Dynamic Scheduling Service shall be negotiated by the Transmission Provider and the ERCOT Ancillary Services Customer, but shall not be more than the maximum rates or less than the minimum rates set forth below, applied to the amount of Non-Spinning Reserve Service provided to the ERCOT IO on behalf of the Customer: $66.00 per transaction per day. In addition, the ERCOT Ancillary Services Customer shall pay the capital, operating and maintenance costs associated with computer hardware and software and communications equipment changes that must be made in order that ERCOT Dynamic Scheduling Service can be provided. Such charges shall be stated in the Transmission ERCOT Ancillary Customer's Service Agreement.
(1) For Monthly delivery, not more than $3,632.84/MW or less than $496.67/MW per month.
(2) For Weekly delivery, not more than $838.35/MW or less than $114.62/MW per week.
(3) For Daily delivery, not more than $119.76/MW or less than $16.37/MW per day.
SCHEDULE 13
ERCOT LOAD FOLLOWING SERVICE
Load following consists of the supply of power and energy in response to hour-to-hour changes in the level of load being served.
ERCOT Load Following Service provides power and energy to accommodate changes in load over an hour's time above that load served by hourly block transaction schedules. This may be done by integrating net load change over a predetermined period (less than one hour) and ramping the generation providing the service to the level required to serve the load change. ERCOT Load Following Service differs from load regulation service in that load following may not adequately accommodate moment-to-moment load variations. The capacity component of load following is the difference between the maximum load during the hour and larger of the total hourly scheduled MW transactions during the hour or the minimum load during the hour. Load-schedule imbalance service is used to compensate for any difference between the hourly transaction amount and the minimum load during the hour. Thus, load-following capacity will be never greater than the difference between the minimum and maximum load during the hour. Energy transferred between Control Areas for load following must be accomplished by either static or dynamic schedules.
The rates for capacity used to provide such System Load Following Service shall be negotiated by CPL and WTU and the Transmission Customer, but shall not be more than the maximum rates or less than the minimum rates set forth below, applied to the amount of Load Following used:
(1) For Yearly delivery, not more than $43,594.07/MW or less than $5,960.00/MW per year, payable in equal monthly installments.
(2) For Monthly delivery, not more than $3,632.84/MW or less than $496.67/MW per month.
(3) For Weekly delivery, not more than $838.35/MW or less than $114.62/MW per week.
(4) For Daily delivery, not more than $119.76/MW or less than $16.37/MW per day.
(5) For Hourly delivery, not more than $4.99/MW or less than $.68/MW per hour.
In addition to such capacity charges, CPL and WTU will provide a quote for energy cost at the time a request for Ancillary Services is made. This quote may be up to 110% of the anticipated cost per megawatt-hour to produce any energy supplied to the Transmission Customer. The anticipated cost shall reflect the Transmission Provider's best estimate at the time the transaction is arranged of such production costs including without limitation the costs of fuel, start-up costs, other variable operating and maintenance expenses and taxes not based on income. This quotation will not be subject to "true-up," and, if accepted, shall be binding on both CPL and WTU, as applicable, and the Transmission Customer.
If a Transmission Customer prefers not to transact on the basis of a binding quote for the energy component given in advance of the services being provided, CPL and WTU may charge for energy based on up to 110% of the actual incremental cost of producing the energy. The Transmission Customer shall also pay the capital, operating and maintenance costs associated with computer hardware and software and communications equipment changes that must be made in order that Load Following service can be provided. Such charges will be detailed in the Service Agreement.
SCHEDULE 14
ERCOT LOAD REGULATION SERVICE
Load regulation service consists of the supply of power and energy in response to intra-hour changes in the load being served.
ERCOT Load Regulation Service provides for moment-to-moment changes in transaction levels so that the transaction can follow the partial capacity requirement of a load not provided by internal generation, static or dynamic schedules, or load following. ERCOT and applicable NERC control criteria for load following will apply. Only generation equipped with and controlled by automatic generation control capability may provide this service. Any accumulated energy resulting from load regulation may be classified as an economy energy transaction.
The rates for capacity used to provide such ERCOT Load Regulation Service shall be negotiated by CPL and WTU and the ERCOT Ancillary Services Customer, but shall not be more than the maximum rates or less than the minimum rates set forth below, applied to the amount of Load Regulation used:
(1) For Yearly delivery, not more than $44,148.84/MW or less than $5,960/MW per year, payable in equal monthly installments.
(2) For Monthly delivery, not more than $3,679.07/MW or less than $496.67/MW per month.
(3) For Weekly delivery, not more than $849.02/MW or less than $114.62/MW per week.
(4) For Daily delivery, not more than $121.29/MW or less than $16.37/MW per day.
(5) For Hourly delivery, not more than $5.05/MW or less than $.68/MW per hour.
In addition to such capacity charges, CPL and WTU will provide a quote for energy cost at the time a request for ERCOT Ancillary Services is made. This quote may be up to 110% of the anticipated cost per megawatt-hour to produce any energy supplied to the ERCOT Ancillary Services Customer. The anticipated cost shall reflect CPL's and WTU's best estimate at the time the transaction is arranged of such production costs including without limitation the costs of fuel, start-up costs, other variable operating and maintenance expenses and taxes not based on income. This quotation will not be subject to "true-up," and, if accepted, shall be binding on both CPL and WTU, as applicable, and the ERCOT Ancillary Services Customer.
If an ERCOT Ancillary Services Customer prefers not to transact on the basis of a binding quote for the energy component of ERCOT Ancillary Services given in advance of the services being provided, CPL and WTU may charge for energy based on up to 110% of the actual incremental cost of producing the energy. Such charges will be detailed in the ERCOT Ancillary Services Customer's Service Agreement. The ERCOT Ancillary Services Customer shall also pay the capital, operating and maintenance costs associated with computer hardware and software and communications equipment changes that must be made in order that ERCOT Load Regulation Service can be provided.
Notwithstanding the above, the floor price for transactions up to and including one year in length will be no less than CPL's and WTU's short-run marginal cost determined in accordance with Texas Public Utility Regulatory Act § 2.001(c); the floor price for transactions lasting longer than one year will be no less than CPL's and WTU's long-run marginal cost determined in accordance with Texas Public Utility Regulatory Act § 2.001(c). Should the floor price as calculated per the description above exceed the ceiling price, the price charged will be the ceiling price.
SCHEDULE 15
ERCOT GENERATION-SCHEDULING IMBALANCE SERVICE
Generation-schedule imbalance service compensates for energy mismatches between the scheduled and actual transmission of power between the seller of power and the provider of transmission service in the supply host's Control Area.
ERCOT Generation-Scheduling Imbalance Service consists of the supply of energy to cover any mismatch between what is scheduled, and what is being provided by the seller of power to the Control Area host. These mismatches differ from backup requirements in that they are typically not intended, recognized, or preventable in real time. These mismatches may occur due to factors including, but not limited to, meter calibration errors, telemetry errors, timing errors, governor response, and interruption of schedules. This energy differs from inadvertent energy in that the imbalance can only be supplied by the supply host Control Area, not other Control Areas. In cases where the seller and the buyer of power are in the same Control Area, the energy mismatch will be between the seller and the supply host Control Area.
Charges for ERCOT Generation-Scheduling Imbalance Service shall be the greater of $100 per megawatt hour of energy supplied or the sum of the capacity and energy charges determined by applying the rates described below.
The rates for capacity used to provide such ERCOT Generation-Scheduling Imbalance Service shall be negotiated by CPL and WTU and the ERCOT Ancillary Services Customer, but shall not be more than the maximum rates or less than the minimum rates set forth below, applied to the amount of capacity so used:
(1) For Yearly delivery, not more than $43,594.07/MW or less than $5,960.00/MW per year, payable in equal monthly installments.
(2) For Monthly delivery, not more than $3,632.84/MW or less than $496.67/MW per month.
(3) For Weekly delivery, not more than $838.35/MW or less than $114.62/MW per week.
(4) For Daily delivery, not more than $119.76/MW or less than $16.37/MW per day.
(5) For Hourly delivery, not more than $4.99/MW or less than $.68/MW per hour.
In addition to such capacity charges, CPL and WTU will provide a quote for energy cost at the time a request for ERCOT Ancillary Services is made. This quote may be up to 110% of the anticipated cost per megawatt-hour to produce any energy supplied to the ERCOT Ancillary Services Customer. The anticipated cost shall reflect CPL's and WTU's best estimate at the time the transaction is arranged of such production costs including without limitation the costs of fuel, start-up costs, other variable operating and maintenance expenses and taxes not based on income. This quotation will not be subject to "true-up," and, if accepted, shall be binding on both CPL and WTU, as applicable, and the ERCOT Ancillary Services Customer.
If an ERCOT Ancillary Services Customer prefers not to transact on the basis of a binding quote for the energy component of ERCOT Ancillary Services given in advance of the services being provided, CPL and WTU may charge for energy based on up to 110% of the actual incremental cost of producing the energy.
Notwithstanding the above, the floor price for transactions up to and including one year in length will be no less than CPL's and WTU's short-run marginal cost determined in accordance with Texas Public Utility Regulatory Act § 2.001(c); the floor price for transactions lasting longer than one year will be no less than CPL's and WTU's long-run marginal cost determined in accordance with Texas Public Utility Regulatory Act § 2.001(c). Should the floor price as calculated per the description above exceed the ceiling price, the price charged will be the ceiling price.
SCHEDULE 16
ERCOT LOAD-SCHEDULE IMBALANCE SERVICE
Load-schedule imbalance service consists of the supply of energy to cover energy mismatches between the scheduled and actual transmission of power between the seller of power and the provider of transmission service in the load host's Control Area.
Such mismatches differ from backup requirements in that they are typically not intended, recognized, or preventable in real time. Such mismatches may occur due to factors including, but not limited to, meter calibration errors, telemetry errors, timing errors, load swings, and interruption of schedules. This service differs from inadvertent energy in that the imbalance can only be supplied by the load host Control Area, not other Control Areas. This service differs from load following service in that load following is used to cover the difference between maximum load during the hour and the larger of the total hourly scheduled MW transactions during the hour or the minimum load during the hour. ERCOT Load-schedule Imbalance Service is used to compensate for any difference between the hourly transaction schedule amount and the minimum load during the hour. In cases where the seller and the buyer of power are in the same Control Area, the energy mismatch will be between the buyer and the supply host Control Area.
Charges for ERCOT Load-Schedule Imbalance Service shall be the greater of $100 per megawatt hour of energy supplied or the sum of the capacity and energy charges determined by applying the rates described below.
The rates for capacity used to provide ERCOT Load-Schedule Imbalance Service shall be negotiated by CPL and WTU and the ERCOT Ancillary Services Customer, but shall not be more than the maximum rates or less than the minimum rates set forth below, applied to the amount of capacity so used:
(1) For Yearly delivery, not more than $43,594.07/MW or less than $5,960.00/MW per year, payable in equal monthly installments.
(2) For Monthly delivery, not more than $3,632.84/MW or less than $496.67/MW per month.
(3) For Weekly delivery, not more than $838.35/MW or less than $114.62/MW per week.
(4) For Daily delivery, not more than $119.76/MW or less than $16.37/MW per day.
(5) For Hourly delivery, not more than $4.99/MW or less than $.68/MW per hour.
In addition to such capacity charges, CPL and WTU will provide a quote for energy cost at the time a request for ERCOT Ancillary Services is made. This quote may be up to 110% of the anticipated cost per megawatt-hour to produce any energy supplied to the ERCOT Ancillary Services Customer. The anticipated cost shall reflect CPL's and WTU's best estimate at the time the transaction is arranged of such production costs including without limitation the costs of fuel, start-up costs, other variable operating and maintenance expenses and taxes not based on income. This quotation will not be subject to "true-up," and, if accepted, shall be binding on both CPL and WTU, as applicable, and the ERCOT Ancillary Services Customer.
If an ERCOT Ancillary Services Customer prefers not to transact on the basis of a binding quote for the energy component of ERCOT Ancillary Services given in advance of the services being provided, CPL and WTU may charge for energy based on up to 110% of the actual incremental cost of producing the energy.
Notwithstanding the above, the floor price for transactions up to and including one year in length will be no less than CPL's and WTU's short-run marginal cost determined in accordance with Texas Public Utility Regulatory Act § 2.001(c); the floor price for transactions lasting longer than one year will be no less than CPL's and WTU's long-run marginal cost determined in accordance with Texas Public Utility Regulatory Act § 2.001(c). Should the floor price as calculated per the description above exceed the ceiling price, the price charged will be the ceiling price.
SCHEDULE 17
ERCOT SCHEDULED BACKUP SERVICE
Scheduled backup service consists of scheduling services for capacity and energy required to replace a capacity resource on a planned or scheduled basis.
This is a type of backup energy service that is arranged in advance with the scheduled backup supplier. The most common usage occurs when a generator supplying energy and capacity for a transaction is to be taken out of service for planned maintenance, but the buyer of the scheduled backup service wishes to continue the transaction. The service may be implemented by means of a static or dynamic schedule, and can be provided by any generator.
The rates for ERCOT Scheduled Backup Service shall be negotiated by CPL and WTU and the ERCOT Ancillary Services Customer, but shall not be more than the maximum rates for capacity plus the rate for energy supplied or less than the rate for energy supplied as set forth below:
(1) For Yearly delivery, not more than $43,594.07/MW or less than $5,960.00/MW per year, payable in equal monthly installments.
(2) For Monthly delivery, not more than $3,632.84/MW or less than $496.67/MW per month.
(3) For Weekly delivery, not more than $838.35/MW or less than $114.62/MW per week.
(4) For Daily delivery, not more than $119.76/MW or less than $16.37/MW per day.
(5) For Hourly delivery, not more than $4.99/MW or less than $.68/MW per hour.
CPL and WTU will provide a quote for energy cost at the time a request for ERCOT Ancillary Services is made. This quote may be up to 110% of the anticipated cost per megawatt-hour to produce any energy supplied to the ERCOT Ancillary Services Customer. The anticipated cost shall reflect CPL's and WTU's best estimate at the time the transaction is arranged of such production costs including without limitation the costs of fuel, start-up costs, other variable operating and maintenance expenses and taxes not based on income. This quotation will not be subject to "true-up," and, if accepted, shall be binding on both CPL and WTU, as applicable, and the ERCOT Ancillary Services Customer.
If an ERCOT Ancillary Services Customer prefers not to transact on the basis of a binding quote for the energy component of ERCOT Ancillary Services given in advance of the services being provided, CPL and WTU may charge for energy based on up to 110% of the actual incremental cost of producing the energy.
Notwithstanding the above, the floor price for transactions up to and including one year in length will be no less than CPL's and WTU's short-run marginal cost determined in accordance with Texas Public Utility Regulatory Act § 2.001(c); the floor price for transactions lasting longer than one year will be no less than CPL's and WTU's long-run marginal cost determined in accordance with Texas Public Utility Regulatory Act § 2.001(c). Should the floor price as calculated per the description above exceed the ceiling price, the price charged will be the ceiling price.
SCHEDULE 18
ERCOT AUTOMATIC BACKUP SERVICE
Automatic backup service consists of scheduling services, capacity and energy required to replace a capacity resource on an unscheduled basis.
This is a type of backup energy service for which no advance notice is provided to the Service Provider. The service may be implemented by means of a dynamic schedule that is initiated automatically. The most common usage occurs when a generator trips off line unexpectedly. Typically within 10 minutes after the generation loss the supply host is supplying all of the backup energy for the lost generator. Through the use of special control software and hardware, it is possible to assign this service to a particular generator in a supply host Control Area. It is also possible to use automatically interrupted ERCOT loads to provide this service.
The rates for ERCOT Automatic Backup Service shall be negotiated by CPL and WTU and the ERCOT Ancillary Services Customer, but shall not be more than the maximum rates for capacity plus the rate for energy supplied or less than the rate for energy supplied as set forth below:
(1) For Yearly delivery, not more than $43,594.07/MW or less than $5,960.00/MW per year, payable in equal monthly installments.
(2) For Monthly delivery, not more than $3,632.84/MW or less than $496.67/MW per month.
(3) For Weekly delivery, not more than $838.35/MW or less than $114.62/MW per week.
(4) For Daily delivery, not more than $119.76/MW or less than $16.37/MW per day.
(5) For Hourly delivery, not more than $4.99/MW or less than $.68/MW per hour.
CPL and WTU will provide a quote for energy cost at the time a request for ERCOT Ancillary Services is made. This quote may be up to 110% of the anticipated cost per megawatt-hour to produce any energy supplied to the ERCOT Ancillary Services Customer. The anticipated cost shall reflect CPL's and WTU's best estimate at the time the transaction is arranged of such production costs including without limitation the costs of fuel, start-up costs, other variable operating and maintenance expenses and taxes not based on income. This quotation will not be subject to "true-up," and, if accepted, shall be binding on both CPL and WTU, as applicable, and the ERCOT Ancillary Services Customer.
If an ERCOT Ancillary Services Customer prefers not to transact on the basis of a binding quote for the energy component of ERCOT Ancillary Services given in advance of the services being provided, CPL and WTU may charge for energy based on up to 110% of the actual incremental cost of producing the energy. Such charges shall be detailed in the ERCOT Ancillary Services Customer's Service Agreement. The ERCOT Ancillary Services Customer shall also pay the capital, operating and maintenance costs associated with computer hardware and software and communications equipment changes that must be made in order that ERCOT Automatic Backup Service can be provided.
Notwithstanding the above, the floor price for transactions up to and including one year in length will be no less than CPL's and WTU's short-run marginal cost determined in accordance with Texas Public Utility Regulatory Act § 2.001(c); the floor price for transactions lasting longer than one year will be no less than CPL's and WTU's long-run marginal cost determined in accordance with Texas Public Utility Regulatory Act § 2.001(c). Should the floor price as calculated per the description above exceed the ceiling price, the price charged will be the ceiling price.
SCHEDULE 19
ERCOT EMERGENCY ENERGY SERVICE
Emergency energy service consists of the scheduled supply of capacity and energy required to replace a capacity resource in an emergency, where the Transmission Customer makes prior arrangements for such services.
This is a pre-arranged form of backup energy service that can be called on immediately when needed. It differs from scheduled backup in that there is no advance notice requirement and it differs from automatic backup in that it does not automatically occur; instead, it is requested by the Transmission Customer when needed. The Service Provider incurs an obligation to provide the service immediately upon request by the Transmission Customer. Whether it is needed will depend upon the degree of firmness required by the parties involved in the transaction to be backed up.
Charges for ERCOT Emergency Energy Service shall be the greater of $100 per megawatt hour of energy supplied or the sum of the capacity and energy charges determined by applying the rates described below.
The rates for capacity used to provide ERCOT Emergency Energy Service shall be negotiated by CPL and WTU and the ERCOT Ancillary Services Customer, but shall not be more than the maximum rates or less than the minimum rates set forth below:
(1) For Yearly delivery, not more than $43,594.07/MW or less than $5,960.00/MW per year, payable in equal monthly installments.
(2) For Monthly delivery, not more than $3,632.84/MW or less than $496.67/MW per month.
(3) For Weekly delivery, not more than $838.35/MW or less than $114.62/MW per week.
(4) For Daily delivery, not more than $119.76/MW or less than $16.37/MW per day.
(5) For Hourly delivery, not more than $4.99/MW or less than $.68/MW per hour.
In addition to such capacity charges, CPL and WTU will provide a quote for energy cost at the time a request for ERCOT Ancillary Services is made. This quote may be up to 110% of the anticipated cost per megawatt-hour to produce any energy supplied to the ERCOT Ancillary Services Customer. The anticipated cost shall reflect CPL's and WTU's best estimate at the time the transaction is arranged of such production costs including without limitation the costs of fuel, start-up costs, other variable operating and maintenance expenses and taxes not based on income. This quotation will not be subject to "true-up," and, if accepted, shall be binding on both CPL and WTU, as applicable, and the ERCOT Ancillary Services Customer.
If an ERCOT Ancillary Services Customer prefers not to transact on the basis of a binding quote for the energy component of ERCOT Ancillary Services given in advance of the services being provided, CPL and WTU may charge for energy based on up to 110% of the actual incremental cost of producing the energy.
Notwithstanding the above, the floor price for transactions up to and including one year in length will be no less than CPL's and WTU's short-run marginal cost determined in accordance with Texas Public Utility Regulatory Act § 2.001(c); the floor price for transactions lasting longer than one year will be no less than CPL's and WTU's long-run marginal cost
determined in accordance with Texas Public Utility Regulatory Act § 2.001(c). Should the floor price as calculated per the description above exceed the ceiling price, the price charged will be the ceiling price.
SCHEDULE 2013
LOSS COMPENSATION SERVICE
Capacity and energy losses occur when a Transmission Provider delivers electricity across its Transmission System for a Transmission Customer. A Transmission Customer may elect to (1) supply the capacity and/or energy necessary to compensate the Transmission Provider for such losses, (2) receive an amount of electricity at delivery points that is reduced by the amount of losses incurred by the Transmission Provider, or (3) purchase the capacity and/or energy necessary to compensate for such losses from the Transmission Provider, when the Transmission Provider has such capacity and energy available. To the extent the Transmission Provider obtains such power and energy from another supplier, the charges to the Transmission Customer will reflect only a pass-through of the costs charged by that entity. Average losses on the Transmission Provider’s Transmission System will be based on the loss percentages specified in Part II, Section 15.7 and Part III, Section 28.5 of this Tariff plus, where applicable, losses on the distribution facilities of the Transmission Provider.
ATTACHMENT A
Form Of Service Agreement For
Firm Point-To-Point Transmission Service
1.0 This Service Agreement, dated as of _______________, is entered into, by and between American Electric Power Service Corporation, the Designated Agent for the AEP Operating Companies (the "Transmission Provider"), and ____________ ("Transmission Customer").
2.0 The Transmission Customer has been determined by the Transmission Provider to have a Completed Application for Firm Point-To-Point Transmission Service under the Tariff.
3.0 The Transmission Customer has provided to the Transmission Provider an Application deposit in the amount of $_________, or the deposit requirement has been waived, in accordance with the provisions of Section 17.3 of the Tariff.
4.0 Service under this agreement shall commence on the later of (1) the requested service commencement date, or (2) the date on which construction of any Direct Assignment Facilities and/or Network Upgrades are completed, or (3) such other date as it is permitted to become effective by the Commission. Service under this agreement shall terminate on such date as mutually agreed upon by the parties.
5.0 The Transmission Provider agrees to provide and the Transmission Customer agrees to take and pay for Firm Point-To-Point Transmission Service in accordance with the provisions of Part II of the Tariff and this Service Agreement.
6.0 The Transmission Customer also agrees that there shall be added to any amount calculated pursuant to the Tariff an amount in dollars sufficient to reimburse the Transmission Provider for any amounts paid or payable by the Transmission Provider as sales, excise or similar taxes (other than taxes based upon or measured by net income) in respect of the total amount payable to the Transmission Provider pursuant to the Tariff, in order to allow the Transmission Provider, after provision for such taxes, to realize the net amount payable to them under the Tariff.
7.0 Any notice or request made to or by either Party regarding this Service Agreement shall be made to the representative of the other Party as indicated below.
Transmission Provider:
American Electric Power Service Corporation
Attn: Director, Transmission and Interconnection Services
1 Riverside Plaza
Columbus, OH 43215-2373
Transmission Customer:
_____________________________________
_____________________________________
_____________________________________
_____________________________________
8.0 The Tariff is incorporated herein and made a part hereof.
9.0 The OASIS Standards and Protocols document states that if a Transmission Provider approves a request for service, the Transmission Customer must confirm. Once the Transmission Customer confirms an approved request, a reservation is considered to exist. In order for a request to remain valid, the Transmission Customer must confirm within the reservation timing requirements found in the Business Practice Standards for Open Access Same-Time Information System (OASIS) Transactions document adopted by the Commission or the request will be deemed withdrawn.
IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be executed by their respective authorized officials.
Transmission Provider:
By:__________________________ ________________ _____________
Name Title Date
Transmission Customer:
By:__________________________ ________________ _____________
Name Title Date
Specifications For Long-Term Firm Point-To-Point
Transmission Service
1.0 Term of Transaction: _______________________________________
Start Date: ________________________________________________
Termination Date: __________________________________________
2.0 Description of capacity and energy to be transmitted by Transmission Provider including the electric Control Area in which the transaction originates.
____________________________________________________________
3.0 Point(s) of Receipt: ______________________________________
Delivering Party: _________________________________________
4.0 Point(s) of Delivery: _____________________________________
Receiving Party: __________________________________________
5.0 Maximum amount of capacity and energy to be transmitted
(Reserved Capacity): ______________________________________
6.0 Designation of party(ies) subject to reciprocal service
obligation: ________________________________________________
____________________________________________________________
____________________________________________________________
7.0 Name(s) of any Intervening Systems providing transmission
service: __________________________________________________
____________________________________________________________
8.0 Service under this Agreement may be subject to some combination of the charges detailed below. (The appropriate charges for individual transactions will be determined in accordance with the terms and conditions of the Tariff.)
8.1 Transmission Charge:__________________________________________
____________________________________________________________
8.2 System Impact and/or Facilities Study Charge(s):
____________________________________________________________
____________________________________________________________
8.3 Direct Assignment Facilities Charge: _____________________________
____________________________________________________________
8.4 Ancillary Services Charges: _____________________________________
____________________________________________________________
____________________________________________________________
____________________________________________________________
____________________________________________________________
____________________________________________________________
____________________________________________________________
8.5 Power Factor: ________________________________________________
8.6 Local Distribution Facilities Charge: ______________________________
____________________________________________________________
ATTACHMENT B
Form Of Service Agreement For Non-Firm
Point-To-Point Transmission Service
1.0 This Service Agreement, dated as of _______________, is entered into, by and between American Electric Power Service Corporation, the Designated Agent for the AEP Operating Companies (the "Transmission Provider"), and ________________ ("Transmission Customer").
2.0 The Transmission Customer has been determined by the Transmission Provider to be a Transmission Customer under Part II of the Tariff and has filed a Completed Application for Non-Firm Point-To-Point Transmission Service in accordance with Section 18.2 of the Tariff.
3.0 Service under this Agreement shall be provided by the Transmission Provider upon request by an authorized representative of the Transmission Customer.
4.0 The Transmission Customer agrees to supply information the Transmission Provider deems reasonably necessary in accordance with Good Utility Practice in order for it to provide the requested service.
5.0 The Transmission Provider agrees to provide and the Transmission Customer agrees to take and pay for Non-Firm Point-To-Point Transmission Service in accordance with the provisions of Part II of the Tariff and this Service Agreement.
6.0 The Transmission Customer also agrees that there shall be added to any amount calculated pursuant to the Tariff an amount in dollars sufficient to reimburse the Transmission Provider for any amounts paid or payable by the Transmission Provider as sales, excise or similar taxes (other than taxes based upon or measured by net income) in respect of the total amount payable to the Transmission Provider pursuant to the Tariff, in order to allow the Transmission Provider, after provision for such taxes, to realize the net amount payable to them under the Tariff.
7.0 Any notice or request made to or by either Party regarding this Service Agreement shall be made to the representative of the other Party as indicated below.
Transmission Provider:
American Electric Power Service Corporation
Attn: Director, Transmission and Interconnection Services
1 Riverside Plaza
Columbus, OH 43215-2373
Transmission Customer:
___________________________________
___________________________________
___________________________________
___________________________________
8.0 The Tariff is incorporated herein and made a part hereof.
IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be executed by their respective authorized officials.
Transmission Provider:
By:__________________________ ________________ _____________
Name Title Date
Transmission Customer:
By:__________________________ ________________ _____________
Name Title Date
ATTACHMENT C
Methodology To Assess Available Transmission Capability
Available Transmission Capability will be determined under the framework established by the North American Electric Reliability Council (NERC). A copy of NERC's "Available Transfer Capability Definitions and Determination," approved May, 1996, is incorporated herein by reference.
In conjunction with the issuance of "Available Transfer Capability Definitions and Determination," NERC directed each of the reliability councils to "... develop procedures for the determination and posting of available transfer capabilities and the allocation of transmission services (including reservations and scheduling), taking into account the ATC principles ..." contained in the NERC document. Each region has developed and submitted such procedures and implementation plans to NERC. The AEP Operating Companies, as members of ECAR, the SPP or ERCOT, intend to comply with the procedures and implementation plans adopted by such reliability councils to assess Available Transmission Capability.
ATTACHMENT D
Methodology for Completing a System Impact Study
The American Electric Power Service Corporation (AEPSC), as agent for the AEP Operating Companies, will evaluate and plan the Transmission System to deliver power from the Transmission Customer's designated receipt points and to the Transmission Customer's designated delivery points on the same basis as AEPSC assesses and plans transmission capacity to serve the Native Load Customers of the AEP Operating Companies.
AEPSC will include the Transmission Customer's loads and power supplies in its overall transmission planning process, as appropriate, to evaluate the availability of capacity to transmit the Transmission Customer's power supplies to the Transmission Customer's loads and identify any operational and/or facility changes which may be required to effect reliable transmission of such power. The transmission planning process used by AEPSC is described in the "American Electric Power FERC Form 715-Annual Transmission Planning and Evaluation Report." AEPSC also complies with the NERC planning standards, ECAR Document No. 1, SPP criteria, and ERCOT planning criteria as appropriate.
Specifically, Part 4 of FERC Form 715 describes the criteria used by AEPSC to assess and plan the Transmission System to meet the AEP Operating Companies' load responsibilities. Part 5 of FERC Form 715 provides a description of the modeling and study considerations used in the transmission planning process. The following is a description of the transmission planning process and testing criteria used by AEPSC in the assessment and planning of the Transmission System to provide Network Integration Service and Point-To-Point Transmission Services.
1. PLANNING PROCESS
The planning process provides the focus for establishing an appropriate level of transmission system reliability. That process encompasses a continuum of activities from near-term assessments, or appraisals, of system performance to long-term facility addition studies and longer-term strategic planning. The planning process typically begins with a deterministic appraisal of Transmission System performance. When such appraisals identify potential problems, detailed studies are conducted to evaluate the severity of the problem and to develop an optimal plan to remove or mitigate the deficiency.
Near-term assessments, also referred to as operational planning, look ahead up to one year. These appraisals verify that the Transmission System, as planned and built based on long-term predictions and assumptions, is adequate to meet the actual requirements that emerge. Delays in transmission reinforcements, and changing power flow patterns or performance expectations, also influence the need for short-term appraisals. These appraisals also provide an early warning of future system reinforcement needs. Operational planning appraisals are conducted in a manner similar to facility planning appraisals. The major difference is that problems cannot be corrected by transmission reinforcements due to insufficient lead time. Short-term studies focus on emerging system problems and on establishing operating procedures to mitigate, as much as possible, any transmission problems detected by the operators.
Long-term facility planning appraisals analyze anticipated system conditions over a time period from l to 10 years into the future. Long-term planning of the Transmission System allows adequate time to identify emerging trends and system deficiencies and then to plan and build needed transmission reinforcements, including time for lengthy regulatory approval processes. Conceptual strategic planning studies beyond the 10-year period provide process as well as framework for coordinating the development of specific transmission reinforcements that have differing time and spatial attributes.
Long-term facility planning and near-term operational planning studies are typically conducted for the Transmission System in accordance with the transmission testing criteria described in Section 2. The majority of these studies are conducted internally by AEPSC system planners, using information generally available from neighboring electric utilities and from Transmission Customers. However, as needed, joint planning studies involving one or more neighboring systems may be carried out to assess and enhance interfaces between the AEP Operating Companies and their neighbors through coordinated operating procedures or development of new interconnection facilities.
Using the process described above, AEPSC will develop plans and recommendations for the AEP Operating Companies regarding facilities that they should construct and place into service to assure sufficient transmission capacity will be available to deliver power from the Transmission Customer's resources to the Customer's load on a basis comparable to the delivery by the Transmission Provider of the resources of the AEP Operating Companies to their respective Native Load Customers.
2. TRANSMISSION TESTING CRITERIA
2.1 Steady State Testing Criteria
The planning process for the Transmission System embraces two major sets of testing criteria to ensure reliability. The first set, which applies to both bulk transmission and local area transmission assessment and planning, includes all critical single and double contingencies. The second set, which is applicable only to the bulk transmission system, includes more severe multiple contingencies (such as those found in ECAR Document No. l) and is primarily intended to test the potential for system cascading faults.
For bulk transmission planning, the testing criteria are deterministic in nature; these outages serve as surrogates for a broad range of actual operating conditions that the power system will have to withstand in a reliable fashion.
2.2 Single and Double Contingencies
The testing criteria for area transmission are usually limited to single-contingencies for the LV transmission system (23 kV to 88 kV) and single or double contingencies for the HV transmission system (138 kV and 161 kV). This contrasts with the criteria for the EHV transmission system, where more severe multiple contingencies are also considered.
Contingencies include the forced or scheduled outage of generating units, transmission circuits, transformers, or other equipment. In general, a single contingency is defined as the outage of any one of these facilities. A single facility is defined based on the arrangement of automatic protective devices. Double circuit tower outages, breaker failures, station outages, common right-of-way outages, and other common mode failures may be a single or double contingency failure depending on established practice in the applicable reliability region.
Double contingencies, being a more severe test of system performance, are used as a surrogate for the significant uncertainties that are inherent in the planning process. Double contingency tests are frequently applied in facility planning studies of the bulk transmission and HV area transmission systems of AEP. Typically, these tests determine the need for bulk transmission system reinforcements and major enhancements to 138 kV systems.
Single contingencies are tested with firm transfers, third-party transfers, and the expected level of AEP opportunity transfers, i.e., the desired first contingency total transfer capability (FCTTC) level. Double contingencies are also tested with the maximum expected level of AEP firm transfers and third-party transfers which affect the Transmission System. Sensitivity studies are normally conducted for a range of opportunity transfers and generation dispatches to test the robustness of the System.
The performance standards used to assess transmission adequacy and plan for facility reinforcement for single and double contingencies are summarized in the FERC Form 715 reports filed by the AEP Operating Companies. Minimum voltage levels at generating stations and critical load buses, are station specific, but are typically higher than minimum voltages shown in such FERC form reports.
2.3 Multiple Contingencies
The AEPSC criteria and simulated testing are primarily intended to prevent uncontrolled area-wide cascading outages under adverse but credible conditions. The AEP Operating Companies that are members of ECAR plan and operate their bulk transmission facilities to meet the criteria of ECAR Document No. l. The AEP Operating Companies that are members of SPP and ERCOT plan and operate their bulk transmission facilities to meet the SPP planning criteria and ERCOT planning requirements. However, new facilities would not be committed on the basis of local overloads or voltage depressions following the severe multiple contingencies unless those resultant conditions were expected to lead to widespread, uncontrolled outages.
2.4 Stability Testing Criteria
Stability testing covers the entire range of power system dynamics from "first swing" transient stability to oscillatory and steady-state stability. This testing is an essential complement to the steady state analysis embodied in the load flow testing described above.
Power plant transient stability is an important consideration because loss of synchronism of a generating unit or an entire generating plant can cause system instability or uncontrolled area-wide cascading outages. When simulating system contingencies affecting power plant stability, various types of fault and network conditions are analyzed using the transient stability performance testing criteria described in the FERC Form 715 reports filed by the AEP Operating Companies.
Steady-state and oscillatory stability performance problems may be initiated by a wide variety of contingencies or operating conditions on the transmission network. Therefore, a wide variety of network disturbances are considered when testing for steady-state and oscillatory stability problems.
2.5 Power Transfer Testing Criteria
The power transfer capability between two interconnected systems (or subsystems) with all facilities in service or with one or two critical components out of service, indicates the overall strength of the network. Many definitions of power transfer capability are possible, but uniformity is highly desirable for purposes of comparison. Furthermore, transfer capability, however defined, is only accurate for the specific set of system conditions under which it was derived. Therefore, the user of this information needs to be aware of the conditions under which the transfer capability was determined and those factors which could significantly influence the capability.
AEPSC has adopted the definitions of transfer capability, published by NERC in "Transmission Transfer Capability," dated May 1995. The most frequently used transfer capability definition is for First Contingency Incremental Transfer Capability (FCITC) and is quoted below from the referenced NERC publication:
First Contingency Incremental Transfer Capability
FCITC is the amount of electric power, incremental above normal power transfers, that can be transferred over the interconnected transmission system in a reliable manner based on all of the following conditions:
1. For the existing or planned system configuration, and with normal (pre-contingency) operating procedures in effect, all facility loadings are within normal ratings and all voltages are within normal limits,
2. The electric systems are capable of absorbing the dynamic power swings, and remaining stable, following a disturbance that results in the loss of any single electric system element, such as a transmission line, transformer, or generating unit, and
3. After the dynamic power swings subside following a disturbance that results in the loss of any single electric system element as described in 2 above, and after the operation of any automatic operating systems, but before any post-contingency operator-initiated system adjustments are implemented, all transmission facility loadings are within emergency ratings and all voltages are within emergency limits.
With reference to condition l above, in the case where pre-contingency facility loadings reach normal thermal ratings at a transfer level below that at which any first contingency transfer limits are reached, the transfer capability is defined as that transfer level at which such normal ratings are reached. Such a transfer capability is referred to as a normal incremental transfer capability (NITC).
First Contingency Total Transfer Capability (FCTTC) is similar to FCITC except that the base power transfers (between the sending and receiving areas) are added to the incremental transfers to give total transfer capability. The regional reliability councils in which the AEP Operating Companies conduct their business have adopted guidelines for interpreting and applying the NERC transfer capability definitions, and AEP uses these guidelines in its internal studies as well.
ATTACHMENT E-1
Index of Firm Point-To-Point Transmission Service Customers
Under Part II of the Tariff
ACN Power, Inc.
AEPSC Power Marketing and Trading Division
AES Power, Inc.
Allegheny Energy Supply Company (formerly dba West Penn Power)
Allegheny Power Service Corporation
Amerada Hess Corporation
Ameren Services Company
American Energy Solutions, Inc.
American Municipal Power-Ohio, Inc.
Amoco Energy Trading Corporation
Aquila Power Corporation
Atlantic City Electric Company
AYP Energy, Inc.
Bedford, Va (City Of)
Bryan, Ohio (City Of)
Buckeye Power Inc., as Agent for Air Products and Chemicals, Inc.
Buckeye Power Inc., as Agent for The BOC Group Inc.
Buckeye Power Inc., as Agent for The Iams Company
Cargill-Alliant, L.L.C. (formerly dba Heartland Enrg Srv)
Carolina Power and Light Company
Catex-Vitol Electric, L.L.C.
Cinergy Capital & Trading, Inc.
CINergy Operation Companies
Citizens Lehman Power Sales
CLECo Corporation
Cleveland Electric Illuminating Company
Cleveland Public Power
CMS Marketing, Services and Trading Company
CNG Power Services Corp.
Coffeyville, Kansas (City of)
Columbia Power Marketing Corp.
Commonwealth Edison
Consolidated Edison Solutions, Inc.
Constellation Power Source, Inc.
Consumers Energy Company
Continental Energy Services, L.L.C.
Coral Power, L.L.C.
CPS Utilities
Danville, Va (City Of)
Dayton Power and Light Company
Delmarva Power and Light Company
Detroit Edison Company
DTE Energy Trading, Inc.
Duke Power Company
DukeSolutions, Inc.
Dupont Power Marketing, Inc.
Dynegy Power Marketing, Inc.
e prime, inc.
East Kentucky Power Cooperative, Inc.
Eastex Power Marketing, Inc.
Edison Mission Marketing & Trading, Inc.
El Paso Merchant Energy, L.P.
Electric Clearinghouse, Inc.
Energy Transfer Group, L.L.C.
Enerz Corporation
Engage Energy US, L.P. (formerly dba Coastal E.S. Co.)
Engelhard Power Marketing, Inc.
Enron Power Marketing, Inc.
Entergy Power Marketing Corp.
Entergy Services, Inc.
Equitable Power Services, Co.
Federal Energy Sales, Inc.
FirstEnergy Corporation (formerly dba OH Edison)
FirstEnergy Trading & Power Marketing, Inc. (formerly dba Market Responsive Energy, Inc.)
Florida Power and Light Company
FPL Energy Power Marketing, Inc.
Griffin Energy Marketing, L.L.C.
H.Q. Energy Services (U.S.) Inc.
Hoosier Energy REC, Inc.
Illinois Power Company
Illinova Power Marketing, Inc.
Indiana Municipal Power Agency
Industrial Energy Applications, Inc.
Intercoast Power Marketing Company
IUC Power Services
Jay County Electric Cooperative, Inc.
Kentucky Utilities Company
Koch Energy Trading, Inc.
LG&E Power Marketing, Inc.
Louis Dreyfus Electric Power, Inc.
Martinsville, Va (City Of)
Merchant Energy Group of the Americas, Inc.
Merrill Lynch Capital Services, Inc.
Michigan Companies
Michigan Public Power Agency
MidAmerican Energy Company
Midcon Power Services Corporation
MIECO Inc.
Minnesota Power and Light Co.
Morgan Stanley Capital Group, Inc.
New Energy Ventures, L.L.C.
NGE Generation, Inc. (formerly dba NYSEG)
Niagara Mohawk Power Corporation
NIPSCO Energy Services, Inc.
NorAm Energy Services, Inc.
North American Energy Conservation
Northern States Power Company
NP Energy Inc.
Orion Power MidWest
Oglethorpe Power Corporation
Old Mill Power Company
Pacificorp Power Marketing, Inc.
Panenergy Power Services, Inc.
PECO Energy Company – Power Team
PG&E Energy Trading – Power, L.P.
Phibro, Inc.
Plum Street Energy Marketing, Inc.
Potomac Electric Power Company
PP&L, Inc. (formerly dba Pennsylvania Power & Light Co.)
PPL EnergyPlus, LLC (formerly dba PP&L EnergyPlus Co.)
Proliance Energy, L.L.C.
Public Service Company of Colorado
Rainbow Energy Marketing Corporation
Reliant Energy Services, Inc.
Richlands, VA (City Of)
SCANA Energy Marketing, Inc.
Sempra Energy Trading Corporation (formerly dba AIG Trading Corporation)
Shelby, Ohio (City Of)
Southeastern Power Administration
Southern Company Services, Inc.
Southern Energy Marketing, Inc.
Southern Illinois Power Cooperative
Southern Indiana Gas & Electric Company
Southwestern Public Service Company
Stand Energy Corporation
Statoil Energy Trading, Inc.
Strategic Energy Ltd.
Tenaska Power Services Co.
Tennessee Power Company
The Energy Authority, Inc.
The Power Company of America, L.P.
Toledo Edison Company
Tractebel Energy Marketing, Inc.
TransAlta Energy Marketing (U.S.) Inc.
TransCanada Power Corporation
TXU Energy Trading Company (formerly dba Enserch Energy Services, Inc.)
Utilicorp United Inc.
Valero Power Services Company
Virginia Electric and Power Company
VTEC Energy, Inc.
Wabash Valley Power Association, Inc.
Western Power Services, Inc.
Western Resources, Inc.
Williams Energy Services Company
Wisconsin Electric Power Company
Wisconsin Power and Light Company
Wisconsin Public Power Inc. – System Operations
WPS Energy Services, Inc.
ATTACHMENT E-2
Index of Non-Firm Point-to-Point Transmission Service Customers
Under Part II of the Tariff
ACN Power, Inc.
AEPSC Power Marketing And Trading Division
AES Power, Inc.
Allegheny Energy Supply Company (formerly dba West Penn Power)
Allegheny Power Service Corporation
Amerada Hess Corporation
Ameren Services Company
American Energy Solutions, Inc.
American Municipal Power-Ohio, Inc.
Amoco Energy Trading Corporation
Aquila Power Corporation, Inc.
Arkansas Electric Cooperative Corporation
Atlantic City Electric Company
Avista Energy, Inc.
AYP Energy, Inc.
Baltimore Gas & Electric Company
Bedford, Va (City Of)
Buckeye Power Inc., as Agent for Air Products and Chemicals, Inc.
Buckeye Power Inc., as Agent for The BOC Group, Inc.
Buckeye Power Inc., as Agent for The Iams Company
Calpine Power Services Company
Cargill-Alliant, L.L.C. (formerly dba Heartland Enrg Srv)
Carolina Power And Light Company
Catex-Vitol Electric, L.L.C.
Central Louisiana Electric Company
Central Power and Light Company
Central Illinois Public Service Company
Cincinnati Gas & Electric Co./PSI Energy, Inc.
Cinergy Capital & Trading, Inc.
CINergy Operation Companies
Citizens Lehman Powers Sales
CLECO Corporation
Cleveland Electric Illuminating
Cleveland Public Power
CMS Marketing, Services And Trading Company
CNG Power Services Corp.
Columbia Energy Power Marketing, Corp.
Columbia Power Marketing Corp.
Commonwealth Edison Company
ConAgra Energy Services, Inc.
Conectiv Energy Supply, Inc.
Constellation Power Source Inc.
Consumers Energy Company
Continental Energy Services, L.L.C.
Coral Power, LLC
CPS Utilities
Danville, Va (City Of)
Dayton Power And Light Company
Delhi Energy Services, Inc.
Delmarva Power And Light Company
Detroit Edison Company
DTE Energy Trading, Inc.
Duke Energy Trading & Marketing, LLC
Duke/Louis Dreyfus, LLC
Duke Power Company
DukeSolutions, Inc.
DuPont Power Marketing, Inc.
Duquesne Light Company
Dynegy Power Marketing, Inc.
e prime, inc.
East Kentucky Power Cooperative, Inc.
Eastex Power Marketing, Inc.
Edison Mission Marketing & Trading, Inc.
El Paso Merchant Energy, L.P.
Electric Clearinghouse, Inc.
Empire District Electric Company
Energy Transfer Group, LLC
Enerz Corporation
Engage Energy US, L.P.
Engelhard Power Marketing, Inc.
Enron Power Marketing, Inc.
Entergy Power Inc.
Entergy Power Marketing Corporation
Entergy Services, Inc.
Equitable Power Services Company
Federal Energy Sales, Inc.
FirstEnergy Corporation (formerly dba OH Edison)
FirstEnergy Trading & Power Marketing, Inc.
Florida Power and Light Company
Florida Power Corporation
FPL Energy Power Marketing, Inc.
GPU Energy
Griffin Energy Marketing, L.L.C.
H.Q. Energy Services (U.S.) Inc.
Hamilton Light And Power
Hoosier Energy REC, Inc.
Illinois Power Company
Illinova Power Marketing, Inc.
Indiana Municipal Power Agency
Industrial Energy Applications, Inc.
Intercoast Power Marketing Company
IUC Power Services
Jay County Electric Cooperative, Inc.
Kansas City Power & Light Company
Kentucky Utilities Company
Koch Energy Trading, Inc.
Koch Power Services, Inc.
LG&E Power Marketing, Inc.
Louis Dreyfus Electric Power, Inc.
Louisville Gas And Electric Company
Martinsville, Va (City Of)
Merchant Energy Group of the Americas, Inc.
Merrill Lynch Capital Services, Inc.
Michigan Companies (Consumers Power Co. & Detroit Edison Co.)
Michigan Public Power Agency
MidAmerica Energy Company
Midcon Power Services Corporation
MIECO Inc.
Minnesota Power & Light Company
Morgan Stanley Capital Group, Inc.
National Gas & Electric, L.P.
New Energy Ventures, L.L.C.
NGE Generation, Inc. (formerly dba NYSEG)
Niagara Mohawk Power Corporation
NIPSCO Energy Services, Inc.
NorAm Energy Service, Inc.
North American Energy Conservation
Northeast Utilities Service Company
Northern Indiana Public Service Co.
Northern States Power Company
NP Energy Inc.
OGE Energy Resources
Oglethorpe Power Corporation
Ohio Valley Electric Corporation (Inc. IKEC)
Oklahoma Municipal Power Authority
Old Mill Power Company
Orion Power MidWest
PacifiCorp Power Marketing, Inc.
PanEnergy Power Services, Inc.
PanEnergy Trading and Market Services, L.L.C.
Pasadena Cogeration, L.P.
PECO Energy Company - Power Team
PG&E Energy Trading – Power, L.P.
Phibro, Inc.
Plum Street Energy Marketing, Inc.
Potomac Electric Power Company
PP&L, Inc. (formerly Penn. Power & Light Co.)
PPL EnergyPlus, LLC (formerly dba PP&L EnergyPlus Co.)
Proliance Energy, L.L.C.
Public Service Company of Colorado
Public Service Company of Oklahoma
Public Service Electric and Gas Company
QST Energy Trading, Inc.
Questar Energy Trading Company
Rainbow Energy Marketing Corporation
Reliant Energy Services, Inc.
Richlands, VA (City Of)
SCANA Energy Marketing, Inc.
Sempra Energy Trading Corporation (formerly dba AIG Trading Corp.)
Shelby, Ohio (City Of)
Sonat Power Marketing L.P.
South Carolina Electric & Gas Company
Southern Company Energy Marketing L.P.
Southern Company Services, Inc.
Southern Energy Marketing, Inc.
Southern Illinois Power Cooperative
Southern Indiana Gas & Electric Company
Southwestern Electric Power Company
Southwestern Public Service Company
Stand Energy Corporation
Statoil Energy Services, Inc.
Statoil Energy Trading, Inc.
Strategic Energy Ltd.
Tenaska Power Services Company
Tennessee Power Company
Tennessee Valley Authority
Texas Utilities Electric Company
The Energy Authority, Inc.
The Power Company of America
Toledo Edison Company
Tractebel Energy Marketing, Inc.
TransAlta Energy Marketing (U.S.) Inc.
TransCanada Power Corporation
TXU Energy Trading Company (formerly dba Enserch Energy Services, Inc.)
Union Electric Company
USGEN Power Services, L.P.
UtiliCorp United Inc.
Valero Power Services Company
Virginia Electric and Power Company
Vitol Gas & Electric, L.L.C.
VTEC Energy, Inc.
Wabash Valley Power Association, Inc.
West Texas Utilities Company
Western Power Services, Inc.
Western Resources
Williams Energy Services Company
Wisconsin Electric Power Company
Wisconsin Power And Light Company
Wisconsin Public Power Inc. System
WPS Energy Services, Inc.
ATTACHMENT F
Service Agreement For
Network Integration Transmission Service
This Agreement is entered into this _____ day of _______, 20___, by and between ____________________ ("Transmission Customer") and American Electric Power Service Corporation, as Designated Agent for the AEP Operating Companies ("Transmission Provider"). In consideration of the mutual covenants and agreements herein, it is agreed as follows:
Article 1. Network Integration Transmission Service.
1.1 During the term of this Agreement, as it may be amended from time to time, the Transmission Provider agrees to provide Network Integration Transmission Service for the Transmission Customer, and the Transmission Customer agrees to pay for such service, in accordance with the applicable provisions of the Transmission Provider's Open Access Transmission Tariff ("Tariff") filed with the Federal Energy Regulatory Commission ("Commission"), and the Schedules and Attachments appended thereto, as applicable, and for other costs identified herein or in attachments hereto as incurred on behalf of the Transmission Customer, but not otherwise recovered from the Transmission Customer, pursuant to said Tariff.
1.2 The terms and conditions of such Network Integration Transmission Service shall be governed by the Tariff, as it exists at the time of this Agreement, or as hereafter amended. The Tariff as it currently exists or as hereafter amended is incorporated in this Agreement by reference. In the case of any conflict between this Agreement and the Tariff, the Tariff shall control.
1.3 The Application for Network Integration Transmission Service tendered by the Transmission Customer and accepted by the Transmission Provider for this Agreement is hereby incorporated by this reference and made a part of this Agreement.
1.4 Agreements for System Impact or Facility Studies, if performed in connection with this Agreement, are attached hereto.
1.5 The Service Specifications for Network Integration Transmission Service under this Agreement as requested by the Transmission Customer and accepted by the Transmission Provider, including, without limit, specifications regarding any Ancillary Services provided by the Transmission Provider, the Transmission Customer or third parties, direct assignment facilities, system upgrades, opportunity costs or customer owned network facilities are hereby incorporated by this reference and made a part of this Agreement.
1.6 The Transmission Customer and the Transmission Provider shall coordinate operation of their respective systems as provided for in this Agreement, the Tariff and the Network Operating Agreement. In furtherance thereof, an Operating Committee chartered pursuant to the Network Operating Agreement shall be established.
Article 2. Cost Recovery Protection.
2.1 The coordinated transmission plan of the Transmission Provider and the Transmission Customer will be predicated upon the plans of the respective Parties as to their planned use of the Transmission System, including the Transmission Customer's planned use of external and internal generating capacity. If the Transmission Customer alters the planned level of use of the Transmission System so as to reduce its transmission service payments to Company, the Transmission Customer must compensate the Transmission Provider for the unrecovered cost of any facilities constructed during the term of the Service Agreement to accommodate service that would be reduced as a result of the change in the Transmission Customer's capacity and/or operating plan, less the net present value of incremental transmission revenue, if any, the Transmission Provider would expect to derive by providing transmission service to other customers by using the transmission capacity freed up by the Transmission Customer's change in plans.
Article 3. Effective Date and Term of Agreement.
3.1 This Agreement shall become effective and shall become a binding obligation of the parties on the date on which the last of the following events shall have occurred (effective date):
(a) The Transmission Provider and the Transmission Customer each shall have caused this Agreement to be executed by their duly authorized representatives and each shall have furnished to the other satisfactory evidence thereof or the Transmission Customer has requested the Transmission Provider to file an unexecuted service agreement pursuant to section 29.1 of the Tariff;
(b) This Agreement has been accepted for filing and made effective by order of the Commission under the Federal Power Act, in which case the effective date of this Agreement shall be as specified in the said Commission order. However, if the Commission or any reviewing court, in such order or in any separate order, suspends this Agreement or any part thereof, institutes an investigation or proceeding under the provisions of the Federal Power Act with respect to the justness and reasonableness of the provisions of this Agreement or any other agreement referred to or contemplated by this Agreement, or imposes any conditions, limitations or qualifications under any of the provisions of the Federal Power Act which individually or in the aggregate are determined by Transmission Provider or the Transmission Customer to be adverse to it, then Transmission Provider and Transmission Customer shall promptly renegotiate the terms of this Agreement in light of such Commission or court action. Each Party will use its best efforts to take or cause to be taken all action requisite to the end that this Agreement shall become effective as provided herein at the earliest practicable date.
3.2 This Agreement shall continue for a term of _____ years.
3.3 The Parties agree to request an effective date of ___________.
Article 4. General.
4.1 Any notice given pursuant to this Agreement shall be in writing, delivered by mail postage prepaid, prepaid overnight courier or facsimile, as follows:
If to Transmission Provider: American Electric Power Service Corporation
Attn: Director, Transmission and Interconnection Services
1 Riverside Plaza
Columbus, Ohio 43215-2373
If to Transmission Customer: ____________________________
____________________________
____________________________
____________________________
4.2 The above names and addresses of any Party may be changed at any time by notice to the other parties.
4.3 This Agreement shall inure to the benefit of and be binding upon the successors and assigns of the Parties. This Agreement shall not be assigned by either Party without the written consent of the other Party.
4.4 The Transmission Customer also agrees that there shall be added to any amount calculated pursuant to the Transmission Tariff an amount in dollars sufficient to reimburse the Transmission Provider for any amounts paid or payable by the Transmission Provider as sales, excise or similar taxes (other than taxes based upon or measured by net income) in respect of the total amount payable to the AEP Operating Companies pursuant to the Tariff, in order to allow the AEP Operating Companies, after provision for such taxes, to realize the net amount payable to them under the Tariff.
IN WITNESS WHEREOF, each of the Parties has caused this Agreement to be duly executed.
Transmission Customer Transmission Provider
By:______________________________ By:_________________________
Title: ____________________________ Title:________________________
Date: ____________________________ Date:________________________
ATTACHMENT G
Network Operating Agreement
This Agreement is entered into this _____ day of ___________, 20___, by and between _____________________ ("Transmission Customer") and American Electric Power Service Corporation, as Designated Agent for the AEP Operating Companies ("Transmission Provider"). In consideration of the mutual covenants and agreements herein, it is agreed as follows:
ARTICLE 1. INTERCONNECTED OPERATIONS
1.1 Interconnection and Delivery Points.
The Transmission Customer and the Transmission Provider shall operate their systems in continuous synchronism through such interconnections as the Operating Committee shall, from time to time, designate; such points being points where power and energy may flow from, as well as to, the Transmission Customer. The Transmission Provider and the Transmission Customer, to the extent practicable, shall each maintain the facilities on their respective sides of such points, and other points of delivery to the Transmission Customer's load centers, in accordance with Good Utility Practice, each at its own expense, in order that said facilities will operate in a reliable and satisfactory manner, and without material reduction in their intended capacity or purpose.
If the function of any such facility is impaired or the capacity of any point of interconnection or delivery is reduced or such synchronous operation at any point or points of interconnection or delivery becomes interrupted, either manually or automatically, as a result of force majeure or maintenance coordinated by the Parties, the Transmission Provider and the Transmission Customer will cooperate to remove the cause of such impairment, interruption or reduction, so as to restore normal operating conditions expeditiously.*
1.2 Scheduling.
The Transmission Customer shall provide the Transmission Provider a schedule in accordance with applicable NERC and Regional Reliability Council Policies setting forth the energy to be received into any AEP Control Area on behalf of the Transmission Customer, during the following day, at each interface between the Transmission System and other Control Areas, in accordance with the provisions of the Tariff. The Transmission Customer shall submit all energy delivery schedules electronically in a form specified by the Transmission Provider. Thereafter, the Transmission Customer may make changes in such schedules upon such notice and with such frequency as is the standard practice of the Transmission Provider, or as agreed by the Operating Committee.
ARTICLE 2. SERVICE CONDITIONS
2.1 Priority of Service.
Delivery of power and energy to the Transmission Customer from the Transmission Customer's Network Resources will be on a firm basis, in all respects, of equal priority with the Transmission Provider's other firm and native load customers. Other deliveries to the Transmission Customer will be provided on an as-available basis, consistent with the provisions of the Tariff and regional practices of the applicable AEP Control Area. In the event that operating conditions require that loadings on the Transmission System, a portion thereof, or interconnecting facilities, be reduced, actions to relieve such conditions will be determined and taken on the basis of their efficacy in providing the relief necessary.
2.2 Curtailment.
In the event a transmission constraint or other contingency causes the loss of access to a particular power supply resource, the loss of such resource may also require the curtailment of the Transmission Provider's or Transmission Customer's Network Load unless the Party relying on the resource obtains substitute resources to serve such Network Loads. To the extent that the transmission constraint or contingency entails the loss of access to a particular power supply resource, the Party relying on the resource shall be required to curtail Network Load in an amount equal to the scheduled amount of such resource unless substitute resources are provided by the affected Party within the time that is customary in the affected AEP Control Area for obtaining replacement power supplies.
2.3 Measurement of Network Load.
The Transmission Customer's Network Load shall be measured on an hourly or shorter periodic integrated basis, by suitable metering equipment located at each interconnection and delivery point. The measurements taken and all metering equipment shall be in accordance with the Transmission Provider's standards and practices for similarly determining the Transmission Provider's load. The actual hourly Network Loads, by delivery point, internal generation site and point where power may flow to and from the Transmission Customer, with separate readings for each direction of flow, shall be provided for each calendar month by the fifth business day of the following calendar month or as mutually agreed by the Transmission Provider and the Transmission Customer. If such measurements are provided by the Transmission Customer, the information provided shall be in an electronic format specified by the Transmission Provider. If such measurements are provided by the Transmission Provider, the information shall be made available to the Transmission Customer, upon request, in suitable electronic format, coincidentally with the issuance of the Transmission Provider's billing. If the Transmission Customer is not already being billed the cost of measuring and billing, pursuant to a power sale transaction or otherwise, the Transmission Customer shall compensate the Transmission Provider monthly for such costs, in accordance with the Service Agreement. If either the Transmission Provider or the Transmission Customer requires real-time load or facility status information from the meter points, the other Party shall cooperate, to the extent necessary, in order that such monitoring and telecommunication equipment as shall be needed for such purpose may be installed and maintained during normal business hours common to the Transmission Provider and the Transmission Customer. The Transmission Customer shall compensate the Transmission Provider for such costs if reasonably required in serving the Transmission Customer and operating the network.
ARTICLE 3. COORDINATION OF PLANNING AND OPERATIONS
3.1 Operating Committee.
The Transmission Provider and the Transmission Customer shall each appoint a member and an alternate to a Committee, and so notify the other Party of such appointment(s) in writing. Such appointment(s) may be changed at any time by similar notice. Each member and alternate shall be a responsible person working with the day-to-day operations of their respective system. The Operating Committee shall represent the Transmission Provider and the Transmission Customer in all matters arising under this Operating Agreement and which may be delegated to it by mutual agreement of the Parties hereto.
The principal duties of the Operating Committee shall be as follows:
a. to establish operating, scheduling and control procedures as needed to meet the requirements of coordinated operation and this Agreement;
b. to establish accounting and billing procedures;
c. to coordinate regarding the changing service requirements of the Transmission Customer and the course of action the Parties will pursue to meet such requirements;
d. to coordinate regarding facility construction and maintenance as appropriate, and to the extent agreed by the Parties; and
e. to perform such other duties as may be specifically identified in, or required for the proper function of Part III of the Tariff, the Transmission Customer's Service Agreement or this Agreement.
3.2 Operating Committee Agreements.
Each Party shall cooperate in providing to the Operating Committee all information required in the performance of the Operating Committee’s duties. All decisions and agreements made by the Operating Committee shall be evidenced in writing. The Operating Committee shall have no power to amend the provisions of this Operating Agreement, the Transmission Customer's Service Agreement or the Tariff.
3.3 Operating Committee Meetings.
The Operating Committee shall meet or otherwise conference at least once each calendar year or at the request of either Party upon reasonable notice, and each Party may place items on the meeting agenda. All proceedings of the Operating Committee shall be conducted by its members taking into account the exercise of Good Utility Practice. If the Operating Committee is unable to agree on any matter coming under its jurisdiction, that matter shall be resolved pursuant to Section 12 of the Tariff, or otherwise, as mutually agreed by the Transmission Customer and the Transmission Provider.
3.4 Coordinated Planning.
A subcommittee established by the Operating Committee shall meet or otherwise conference at least once each calendar year to exchange and review all relevant transmission planning data. The Operating Committee, or its designated representatives, will conduct such load flow and other system studies as are necessary to identify any potential constraints on the Transmission System that may limit the Transmission Customer's ability to deliver power and energy from Network Resources to its load centers on an aggregate and individual basis (Base Case Supply Study). The cost of the Base Case Supply Study will be considered a cost of service recovered in the charges paid by Transmission Customer pursuant to its charges for Network Integration Transmission Service for the applicable Control Area. Separate reimbursement shall be made for the cost of additional studies the Transmission Customer requests that go beyond the level of investigation identified by the Operating Committee as sufficient for purposes of Network Resources and Network Load integration.
In the event that studies reveal a potential limitation of the Transmission Customer's ability to deliver power and energy to any of its load centers, the Parties shall identify appropriate remedies for such constraints including, but not limited to: a) construction of new transmission facilities, b) upgrade or other improvements to existing transmission facilities, and c) temporary modification to operating procedures designed to relieve identified constraints. The Transmission Provider will, consistent with Good Utility Practice, endeavor to construct and place into service sufficient transmission capacity to maintain priority of service to the Transmission Customer. An appropriate sharing of the costs of relieving such constraints will be determined by the Parties, consistent with the Commission's rules, regulations, policies and precedents then in effect. If there are no such rules, regulations, policies or precedents, and/or the Parties are unable to agree upon an appropriate sharing of the costs, the Transmission Provider shall submit its proposal for the sharing of such costs to the FERC for approval.
3.5 Network Resource Designation.
Section 30 of the Tariff governs designation, termination, operation and delivery of Network Resources. In furtherance of such Tariff provisions, the Transmission Provider and the Transmission Customer additionally agree that by September 1 of each year during any term of service under the Agreement, the Transmission Customer shall update the generating facilities and/or contractual arrangements (i.e. Network Resources) it will use in the next calendar year to supply its Network Load, including the capacity, in MW, to be available from each resource and the type of capacity, e.g., unit, system, or other types, as detailed in Exhibit A. The Transmission Customer shall also provide at such times a forecast of the diversified monthly peak load to be supplied at each meter point during the corresponding calendar year. The Transmission Customer shall make such designations with as much advance notice as is practicable prior to the initial term of the Service Agreement. Changes in such designations may be made consistent with the Tariff; accordingly, the Transmission Customer shall provide the Transmission Provider as much notice as is practicable in the circumstances.
3.6 Cogeneration and Small Power Production Facilities.
If a Qualifying Facility is located or locates in the future on the Transmission Customer's system and the owner or operator of such Qualifying Facility sells the output of such Qualifying Facility to an entity other than the Transmission Customer, the delivery of such Qualifying Facility’s power and energy to any receiving entity other than Transmission Provider shall be subject to and contingent upon proper transmission and interconnection arrangements being established with the Transmission Provider prior to commencement of delivery of any such power and energy. It is the responsibility of the Transmission Customer to ensure that all Transmission Customer generating units, including Qualifying Facilities and Independent Power Producer generator units specified by the Transmission Customer as a Network Resource, meet all frequency and reactive response requirements. All generator excitation system(s) shall conform to within 80% of the field voltage versus time criteria specified in ANSI Standard C50.13-1989, or the latest revision thereof, in order to permit field forcing during transient conditions. All generator governors shall be able to respond to interconnection frequency deviations and be able to help maintain the interconnection frequency. A Qualifying Facility shall be subject to any installation and operating guidelines, rules, and criteria of NERC, ECAR, SPP, ERCOT and the Transmission Provider.
3.7 Voltage Support.
Transmission Customer will use reasonable best efforts to have in the shortest practicable time, but under no circumstances greater than one year after the request for commencement of service under this Tariff, sufficient reactive compensation and control to (i) meet voltage schedules designated by the Transmission Provider’s operations personnel for each Network Resource or at each interface of the Transmission Provider with the Customer (or designated Control Area) System where the Customer operates a Network Resource behind the interface, or (ii) meet power factor requirements (as may be specified in the Transmission Provider's design criteria as provided in the Transmission Provider's FERC Form 715) at each meter point or Delivery Point behind which the Customer does not operate a Network Resource. If Transmission Customer does not provide the necessary reactive compensation and control to comply with the objectives described in this Article, Transmission Provider shall have the unilateral right to install equipment, including but not limited to the reactive transient response equipment to meet the requirements of Article 3.6, at Transmission Customer's expense.
3.8 Liability and Indemnification.
The provisions of Section 10.2 of the Tariff shall be applicable to the Transmission Customer. In the event that the Transmission Provider determines that Transmission Customer may not have the resources or authority to meet its indemnification obligations under this Tariff, the Transmission Provider may require that Transmission Customer procure, or cause to be procured, a policy or policies of liability insurance to cover generally all indemnifiable liabilities that might arise under this Operating Agreement. The Transmission Provider and its Affiliates shall be designated under such policy or policies as either the named insured or an additional named insured.
ARTICLE 4. GENERAL
4.1 Any notice given pursuant to this Agreement shall be in writing as follows:
If to the Transmission Provider: American Electric Power Service Corporation
Attn: Director, Transmission and Interconnection
Services
1 Riverside Plaza
Columbus, Ohio 43215-2373
If to the Transmission Customer: ____________________________
____________________________
____________________________
____________________________
4.2 The above names and addresses of any Party may be changed at any time by notice to the other Party.
4.3 This Agreement shall inure to the benefit of and be binding upon the successors and assigns of the Parties. This Agreement shall not be assigned by either Party without the written consent of the others.
IN WITNESS WHEREOF, each of the Parties has caused this Agreement to be duly executed.
Transmission Customer Transmission Provider
____________________________ ____________________________
By:_________________________ By:_________________________
Title:________________________ Title:________________________
Date:________________________ Date:________________________
Exhibit A -- Page 1 of 2
ACTUAL AND FORECASTED RESOURCES AND OBLIGATIONS (MW)
FOR TEN YEAR PERIOD ENDING _____
| |
|RESOURCES |
| |
|4 |
|7 |
|TOTAL CAPABILITY |
|8 |
|LOAD RESPONSIBILITY |
|9 |
| |
|13 |
|14 |TARGET % RESERVE MARGIN | |
| | | | | | | | |
|(Purchasing-Selling) | | |Hour |Schedule |Schedule |Start |Ramp |
|Requesting Entity | | | | | | | |
| | | | | | | | |
|* Contact Name | | |Ending |Max MWH |MWH |Stop |Rates |
| | | | | | | | |
|Billing Address | | |(CPT) |Sup/Rec |Sup/Rec |Times |MW/Min. |
| | | | | | | | |
| | | |0100 | | | | |
| | | | | | | | |
| | | |0200 | | | | |
| | | | | | | | |
|Telephone Number | | |0300 | | | | |
| | | | | | | | |
|24 Hour Contact Name | | |0400 | | | | |
| | | | | | | | |
|Fax Number | | |0500 | | | | |
| | | | | | | | |
|**Start/Stop Date(s) | | |0600 | | | | |
| | | | | | | | |
|Supplying Party/Selling | | |0700 | | | | |
|Entity | | | | | | | |
| | | | | | | | |
|Supplying Party/Selling | | |0800 | | | | |
|Entity Phone | | | | | | | |
| | | | | | | | |
|Sending Control Area | | |0900 | | | | |
| | | | | | | | |
|Sending Control Area Phone | | |1000 | | | | |
| | | | | | | | |
|Sending Control Area Fax | | |1100 | | | | |
| | | | | | | | |
|Receiving Party/Purchasing | | |1200 | | | | |
|Entity | | | | | | | |
| | | | | | | | |
|Receiving Control Area | | |1300 | | | | |
| | | | | | | | |
|Receiving Control Area | | |1400 | | | | |
|Phone | | | | | | | |
| | | | | | | | |
|Receiving Control Area Fax | | |1500 | | | | |
| | | | | | | | |
|Contract Intermediary | | |1600 | | | | |
|Control Area | | | | | | | |
| | | | | | | | |
| | | |1700 | | | | |
| | | | | | | | |
| | | |1800 | | | | |
|Transaction Classification | | |1900 | | | | |
|Type: | | | | | | | |
| | | | | | | | |
|Terms of | | |2000 | | | | |
|Interruption/Remarks: | | | | | | | |
| | | | | | | | |
| | | |2100 | | | | |
| | | | | | | | |
| | | |2200 | | | | |
| | | | | | | | |
| | | |2300 | | | | |
| | | | | | | | |
| | | |2400 | | | | |
| | | | | | | | |
|Schedule Chain: | | |Total | | | | |
| | | | | | | | |
Control Area Transaction Scheduler Use Only
| | | | | |
|Rec|Date: |Time: |By: |Ancillary Services: |
|eiv| | | | |
|ed | | | | |
| | | | | |
|***|Date: |Time: |By: | |
|ERC| | | | |
|OT | | | | |
|App| | | | |
|rov| | | | |
|al | | | | |
| | | | | |
|Con|Date: |Time: |By: | |
|tro| | | | |
|l | | | | |
|Are| | | | |
|a | | | | |
|Con| | | | |
|fir| | | | |
|mat| | | | |
|ion| | | | |
* Contact is responsible for notifying all parties of any schedule changes ** For multiple day schedules send a separate request form, by 1400 the day for each
additional day *** Receiving Control Area fax request form to ERCOT
EXHIBIT A-3 DATED ________________
Local Distribution Facilities
ATTACHMENT K
Annual Transmission Revenue Requirement for
ERCOT Regional Transmission Service
Charges for ERCOT Regional Transmission Service provided under Part IV of the Tariff shall be determined as follows:
1. Annual Planned ERCOT Regional Transmission Service Charges
Charges for Annual Planned ERCOT Regional Transmission Service are to be determined by dividing the Annual Facilities Charge by 12, or by other means as mutually agreed upon by the Transmission Provider and the Transmission Customer and specified in the Service Agreement. Under no circumstances shall the sum of the monthly charges due in any calendar year be more or less than the Annual Facilities Charge due under this Tariff.
Annual Facilities Charges are the sum of: (1) the product of the Annual Access Rate for CPL (set forth below) multiplied by the ERCOT Regional Transmission Service Customer's demand at the time of the most recent ERCOT system coincident peak demand, as determined by the PUCT pursuant to Chapter 25; and (2) the product of the Annual Access Rate for WTU (set forth below) multiplied by the ERCOT Regional Transmission Service Customer's demand at the time of the most recent ERCOT system coincident peak demand, as determined by the PUCT pursuant to Chapter 25.
The Annual Access Rate for CPL is $1.256059/kw
The Annual Access Rate for WTU is $0.552034/kw
2. Monthly Retail Transmission System Use Rates
The rates contained in this Section 2 of Attachment K are provided for informational purposes only. As required by Chapter 25 of the PUCT Substantive Rules, the transmission charges of the Transmission Provider under this Tariff (Attachment K, Section 1), and the transmission service charges of other ERCOT transmission service providers will be collected by the local distribution service providers (CPL & WTU) under six customer class specific rates approved by the PUCT. Transmission Charges to Retail Energy Providers serving consumers in the portion of ERCOT where CPL and WTU provide distribution service will be charged per consumer in accordance with the following:
|Customer Class |Billing Unit |Monthly Retail Transmission Use Rate |
| | |Dollars Per Billing Unit |
| | |CPL |WTU |
|1) Residential |Per Meter kWh |$0.0036930 |$0.004614 |
|General Service | | | |
|2) Secondary ( 10 kW |Per Meter kWh |$0.001862 |$0.002432 |
|3) Secondary > 10 kW | | | |
|(a) IDR Meter |4 CP kW Average |$1.37 |$1.37 |
| (b) Non-IDR Meter |NCP kW |$0.97 |$0.93 |
|4) Primary Service | | | |
|(a) IDR Meter |4 CP kW Average |$1.37 |$1.37 |
| (b) Non-IDR Meter |NCP kW |$2.06 |$2.12 |
|5 Transmission Service | | | |
| IDR Meter |4 CP kW Average |$1.37 |$1.37 |
|6 Lighting Service |Per Estimated kWh |$0.001860 |$0.002432 |
2. Other Planned Service Charges
Charges for Other Planned Service are to be determined by multiplying the applicable access rate set forth below by the MW of demand the transmission customer sets forth in the transaction reservation submitted to the ERCOT ISO. Unless the Other Planned Service qualifies as a replacement transaction, charges for Other Planned Service shall be in addition to charges for Annual Planned Service. In the event a requested transaction qualifies as a replacement transaction, the ERCOT ISO will determine the incremental billing units to be applied.
Access Rates for CPL
Monthly $ 104.67
Weekly $ 24.16
Daily $ 3.44
Access Rates for WTU
Monthly $ 46.00
Weekly $ 10.62
Daily $ 1.51
These Rates shall be effective until changed by the Transmission Provider or changed by the Commission.
ATTACHMENT L-1
Index of Planned ERCOT Regional Transmission
Service Customers
American Electric Power Service Corporation
Amoco Energy Trading Corporation
Aquila Power Corporation, Inc.
Avista Energy, Inc.
Big Country Electric Cooperative, Inc.
Brazos Electric Power Cooperative, Inc.
Brazos Power Marketing Cooperative, Inc.
Calpine Power Services Company
Cap Rock Electric Cooperative, Inc.
Cargill-Alliant, LLC
Central Power and Light Company and West Texas Utilities Company
Cincinnati Gas & Electric Co./PSI Energy, Inc.
Citizens Lehman Powers Sales
City of Austin Electric Department
City of Bryan Municipal Electric System
City of College Station, Texas
City of Denton Municipal Utilities
City of Garland, Texas
City of Granbury Municipal Electric Department
City of Hearne, Texas
City of Robstown, Texas
City of Weatherford, Texas
City Public Service Board of San Antonio, Texas
Coleman County Electric Cooperative, Inc.
Columbia Energy Power Marketing Corporation
Concho Valley Electric Cooperative, Inc.
Constellation Power Source
Coral Power, LLC
Delhi Energy Services, Inc.
Duke Energy Trading & Marketing, LLC
Duke/Louis Dreyfus, LLC
DuPont Power Marketing, Inc.
e prime, inc.
El Paso Merchant Energy, LP
Electric Clearinghouse, Inc.
Energy Transfer Group, LLC
Engage Energy US, L.P.
Enron Power Marketing, Inc.
Entergy Power Inc.
Entergy Power Marketing Corporation
Entergy Services, Inc.
Equitable Power Services Company
Florida Power Corporation
FPL Energy Power Marketing, Inc.
Greenville Electric Utilities, Greenville, Texas
Gregory Power Partners, LP
Houston Lighting and Power Company
Kansas City Power & Light Company
Kimble Electric Cooperative, Inc.
Koch Power Services, Inc.
LG&E Power Development, Inc.
LG&E Power Marketing, Inc.
Lighthouse Electric Cooperative, Inc.
Lower Colorado River Authority
Medina Electric Cooperative
Merchant Energy Group of the Americas, Inc.
Minnesota Power & Light Company
Morgan Stanley Capital Group, Inc.
National Gas & Electric L.P.
NorAm Energy Services
NP Energy Inc.
OGE Energy Resources
PacifiCorp Power Marketing, Inc.
PanEnergy Trading and Market Services, L.L.C.
Pasadena Cogeneration, L.P.
PECO Energy Company - Power Team
Public Utilities Board of Brownsville
Questar Energy Trading Company
Rainbow Energy Marketing Corporation
Rayburn Electric Cooperative, Inc.
Rio Grande Cooperative, Inc.
Sharyland Utilities, L.P.
South Texas Electric Cooperative, Inc.
Southern Company Energy Marketing, Inc.
Southern Energy Trading and Marketing, Inc.
Southwest Texas Electric Cooperative, Inc.
Southwestern Electric Service Company
Southwestern Public Service Company
Taylor Electric Cooperative, Inc.
Tenaska
Tex-La Electric Cooperative of Texas, Inc.
Texas Utilities Electric Company
Texas-New Mexico Power Company
The Power Company of America
UtiliCorp United
Valero Power Services Company
Vitol Gas & Electric, L.L.C.
VTEC Energy, Inc.
Western Power Services
Western Resources
Williams Energy Services Company
ATTACHMENT L-2
Index of Unplanned ERCOT Regional Transmission
Service Customers
American Electric Power Service Corporation
Amoco Energy Trading Corporation
Aquila Power Corporation, Inc.
Avista Energy, Inc.
Big Country Electric Cooperative, Inc.
Brazos Electric Power Cooperative, Inc.
Brazos Power Marketing Cooperative, Inc.
Calpine Power Services Company
Cap Rock Electric Cooperative, Inc.
Cargill-Alliant, LLC
Central Power and Light Company and West Texas Utilities Company
Cincinnati Gas & Electric Co./PSI Energy, Inc.
Citizens Lehman Powers Sales
City of Austin Electric Department
City of Bryan Municipal Electric System
City of College Station, Texas
City of Denton Municipal Utilities
City of Garland, Texas
City of Granbury Municipal Electric Department
City of Hearne, Texas
City of Robstown, Texas
City of Weatherford, Texas
City Public Service Board of San Antonio, Texas
Coleman County Electric Cooperative, Inc.
Columbia Energy Power Marketing Corporation
Concho Valley Electric Cooperative, Inc.
Constellation Power Source
Coral Power, LLC
Delhi Energy Services, Inc.
Duke/Louis Dreyfus, LLC
DuPont Power Marketing, Inc.
e prime, inc.
Electric Clearinghouse, Inc.
Energy Transfer Group, LLC
Engage Energy US, L.P.
Enron Power Marketing, Inc.
Entergy Power Inc.
Entergy Power Marketing Corporation
Entergy Services, Inc.
Equitable Power Services Company
Florida Power Corporation
FPL Energy Power Marketing, Inc.
Greenville Electric Utilities, Greenville, Texas
Houston Lighting and Power Company
Kansas City Power & Light Company
Kimble Electric Cooperative, Inc.
Koch Power Services, Inc.
LG&E Power Marketing, Inc.
Lighthouse Electric Cooperative, Inc.
Lower Colorado River Authority
Medina Electric Cooperative
Merchant Energy Group of the Americas, Inc.
Minnesota Power & Light Company
Morgan Stanley Capital Group, Inc.
National Gas & Electric L.P.
NorAm Energy Services
NP Energy Inc.
OGE Energy Resources
PacifiCorp Power Marketing, Inc.
PanEnergy Trading and Market Services, L.L.C.
Pasadena Cogeneration, L.P.
PECO Energy Company - Power Team
Public Utilities Board of Brownsville
Questar Energy Trading Company
Rainbow Energy Marketing Corporation
Rayburn Electric Cooperative, Inc.
Rio Grande Cooperative, Inc.
Sharyland Utilities, L.P.
Sonat Power Marketing L.P.
South Texas Electric Cooperative, Inc.
Southern Company Energy Marketing, Inc.
Southern Energy Trading and Marketing, Inc.
Southwest Texas Electric Cooperative, Inc.
Southwestern Electric Service Company
Southwestern Public Service Company
Taylor Electric Cooperative, Inc.
Tenaska
Tex-La Electric Cooperative of Texas, Inc.
Texas Utilities Electric Company
Texas-New Mexico Power Company
The Power Company of America
UtiliCorp United
Valero Power Services Company
Vitol Gas & Electric, L.L.C.
VTEC Energy, Inc.
Western Power Services
Western Resources
Williams Energy Services Company
ATTACHMENT M
Form of Service Agreement for
ERCOT Ancillary Services
1.0 This Service Agreement, dated as of _______________, is entered into, by and between American Electric Power Service Corporation, as Designated Agent for Central Power and Light Company and West Texas Utilities Company ("the Transmission Provider"), and ____________ ("ERCOT Ancillary Services Customer").
2.0 The ERCOT Ancillary Services Customer has been determined by the Transmission Provider to have submitted a completed Application for ERCOT Ancillary Services under the Tariff, and to have met the creditworthiness requirements of the Tariff.
3.0 Service under this agreement shall commence on the later of (l) the requested Service Commencement Date, or (2) the date on which construction of any Direct Assignment Facilities and/or Network Upgrades are completed, or (3) such other date as it is permitted to become effective by the Commission. Service under this agreement shall terminate on such date as mutually agreed upon by the parties.
4.0 The Transmission Provider agrees to provide and the ERCOT Ancillary Services Customer agrees to take and pay for ERCOT Ancillary Service in accordance with the provisions of Parts I and IV of the Tariff and this Service Agreement.
5.0 Central Power and Light Company and West Texas Utility Company have assumed the duties of or will otherwise arrange for the services of a Qualified Scheduling Entity (QSE) in accordance with applicable requirements for the ERCOT Ancillary Service Customer if the ERCOT Ancillary Service Customer is served from the transmission facilities of and takes total or partial wholesale power supply service from Central Power and Light Company or West Texas Utilities Company pursuant to an existing arrangement on file with and accepted by FERC. The Transmission Provider agrees to provide or arrange for QSE Service and the ERCOT Ancillary Service Customer agrees to take and pay for such Service pursuant to Section 41.9 of the Tariff.
56.0 The ERCOT Ancillary Services Customer also agrees that there shall be added to any amount calculated pursuant to the Tariff an amount in dollars sufficient to reimburse the Transmission Provider for any amounts paid or payable by the Transmission Provider as sales, excise or similar taxes (other than taxes based upon or measured by net income) in respect of the total amount payable to the Transmission Provider pursuant to the Tariff, in order to allow the Transmission Provider, after provision for such taxes, to realize the net amount payable to them under the Tariff.
67.0 Any notice or request made to or by either Party regarding this Service Agreement shall be made to the representative of the other Party as indicated below.
Transmission Provider:
American Electric Power Service Corporation
Attn: Director, Transmission and Interconnection Services
1 Riverside Plaza
Columbus, Ohio 43215-2373
Transmission Customer:
_____________________________________
_____________________________________
_____________________________________
68.0 The Tariff is incorporated herein and made a part hereof.
IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be executed by their respective authorized officials.
Transmission Provider:
By: _______________________ ______________________ ____________________
Name Title Date
Transmission Customer:
By: _______________________ ______________________ ____________________
Name Title Date
DATE: ____________________
Schedule Request Form for
ERCOT Ancillary Services
To arrange for a specific schedule for ERCOT Ancillary Services under Part IV of this Tariff, the ERCOT Ancillary Service Customer should contact the AEP Lead System Operator so that the information required below can be agreed to.
ERCOT Ancillary Services Requested and Charges:
SERVICE REQUESTED RATES CHARGES
Term of Transaction (i.e. hourly, daily, weekly, or monthly or annual):
Start Date:
Termination Date:
ATTACHMENT N
Index of ERCOT Ancillary Service Customers
American Electric Power Service Corporation
Amoco Energy Trading Corporation
Aquila Power Corporation
Big Country Electric Cooperative, Inc.
Brazos Power Marketing Cooperative, Inc.
Calpine Power Services Company
Cap Rock Electric Cooperative, Inc.
Cargill-Alliant, LLC
Cinergy Services, Inc./Cincinnati Gas & Electric
Company/PSI Energy, Inc.
Citizen Lehman Power Sales
City of Austin Electric Department, Austin, Texas
City of Bryan Municipal Electric System
City of College Station, Texas
City of Denton Municipal Utilities
City of Garland, Texas
City of Granbury Municipal Electric Department
City of Hearne, Texas
City of Robstown, Texas
City of Weatherford, Texas
City Public Service Board of San Antonio, Texas
Coleman County Electric Cooperative, Inc.
Columbia Energy Power Marketing Corporation
Concho Valley Electric Cooperative, Inc.
Constellation Power Source
Coral Power, LLC
Delhi Energy Services, Inc.
Duke Energy Hidalgo, L.P.
Duke Energy Trading & Marketing, LLC
Duke/Louis Dreyfus, LLC
DuPont Power Marketing, Inc.
e prime, inc
El Paso Merchant Energy, LP
Electric Clearinghouse, Inc.
Energy Transfer Group, LLC
Engage Energy US, L.P.
Enron Power Marketing, Inc.
Entergy Power Inc.
Entergy Power Marketing Corporation
Entergy Services, Inc.
Equitable Power Services Company
Florida Power Corporation
FPL Energy Power Marketing, Inc.
Frontera Generation Limited Partnership
Greenville Electric Utilities, Greenville, Texas
Gregory Power Partners, L.P.
Houston Lighting & Power Company
Ingleside Cogeneration Limited Partnership (ICP)
Kansas City Power & Light Company
Kimble Electric Cooperative, Inc.
Koch Power Services, Inc.
LG&E Power Marketing, Inc.
Lighthouse Electric Cooperative, Inc.
Lower Colorado River Authority
Medina Electric Cooperative
Merchant Energy Group of the Americas, Inc.
Minnesota Power & Light Company
Morgan Stanley Capital Group, Inc.
National Gas & Electric L.P.
NorAm Energy Services
NP Energy Inc.
OGE Energy Resources
PacifiCorp Power Marketing, Inc.
PanEnergy Trading and Market Services, L.L.C.
Pasadena Cogeneration, L.P.
PECO Energy Company - Power Team
Public Utilities Board of Brownsville
Questar Energy Trading Company
Rainbow Energy Marketing Corporation
Rayburn Electric Cooperative, Inc.
Rio Grande Cooperative, Inc.
South Texas Electric Cooperative, Inc.
Southern Company Energy Marketing LP
Southern Energy Trading and Marketing, Inc.
Southwest Texas Electric Cooperative, Inc.
Southwestern Electric Service Company
Southwestern Public Service Company
Taylor Electric Cooperative, Inc.
Tenaska
Tex-La Electric Cooperative of Texas, Inc.
Texas Utilities Electric Company
Texas-New Mexico Power Company
The Power Company of America
UtiliCorp United
Valero Power Services Company
Vitol Gas & Electric, L.L.C.
VTEC Energy, Inc.
Western Power Services
Western Resources
Williams Energy Services Company
ATTACHMENT O
Appendix 9C1
Transmission Loading Relief Procedure – Eastern Interconnection
Version 2
Appendix Subsections
A. General Requirements
B. Transmission Loading Relief (TLR) Levels
C. Interchange Transaction Curtailment Order
D. Transaction Management and Curtailment Process
E. Principles for Mitigating Constraints On and Off the Contract Path
F. Transaction Contribution Factor Calculation
G. Transaction Curtailment Formula
H. NERC Transmission Loading Relief Procedure Event Log
Introduction
The NERC Transmission Loading Relief (TLR) Procedure is an Eastern Interconnection-wide procedure to allow the Security Coordinators to:
1. Respect Transmission Service reservation priorities, and
2. Mitigate potential or actual Operating Security Limit violations.
Transmission Provider Obligations
NERC recognizes that Transmission Providers are subject to obligations under FERC-approved tariffs or other agreements, and nothing in these procedures shall be interpreted as changing those obligations. This Appendix uses the term “transmission reservation” to mean transmission arranged under the FERC pro forma tariff as well as under other transmission agreements.
Relationship between TLR Procedure and FERC pro forma Tariff
The TLR Procedure has been incorporated into the transmission tariff of many Transmission Providers, and is on file with the Federal Energy Regulatory Commission. The TLR Procedure follows the curtailment provisions of the pro forma tariff with regards to Non-firm and Firm Point-to-Point Transmission Service, and Network Integration Transmission Service.
The pro forma tariff’s curtailment provision addresses the curtailment of the transmission service over the constrained facilities, not curtailment of the generation product being sold via that service. The tariff does not consider the effect of the curtailment on the load-serving entity; instead, it considers the obligations of the Transmission Provider(s) in providing or curtailing the Transmission Service. The NERC TLR Procedure translates the curtailment of the Transmission Service into a curtailment of the actual MW flow over the constraint.
Regarding the curtailment of transmission use by Firm Point-to-Point Transmission Service, the TLR Procedure follows the Federal Energy Regulatory Commission’s pro forma tariff that Transmission Providers are not obligated to redispatch their own resources to maintain Transactions using Firm Point-to-Point Transmission Service before they are curtailed on a pro-rata basis with transmission use for Network Integration Transmission Service and Native Load.
The TLR Procedure includes the Transaction Contribution Factor (TCF), which calculates the portion of the Constrained Facility’s loading due to Firm Point-to-Point Transmission Service. This is one part of the calculation that the Transmission Provider must perform to ensure that this curtailment is comparable and non-discriminatory with the Transmission Provider’s curtailment of Network Integration Transmission Service and Transmission Service for Native Load. (See Section F, “Transaction Contribution Factor Calculation”)
Summary of TLR Levels
|TLR Level|Security Coordinator Action |Comments | |
|1 |Notify Security Coordinators of potential Operating Security Limit | |System |
| |violations | |Secure |
|2 |Hold Interchange Transactions at current levels to prevent Operating |Of those transactions with a 5% or greater impact | |
| |Security Limit violations |on the constrained facility, only those under | |
| | |existing Transmission Service reservations will be | |
| | |allowed to continue, and only to the level existing| |
| | |at the time of the hold. | |
|3a |Curtail Transactions using Non-firm Point-to-Point Transmission |Curtailment follows Transmission Service | |
| |Service to allow Transactions using higher priority Point-to-Point |priorities. | |
| |Transmission Service | | |
|3b |Curtail Transactions using Non-firm Point-to-Point Transmission |Curtailment follows Transmission Service |Security |
| |Service to mitigate Operating Security Limit Violation |priorities. |Limit |
| | | |Violation |
|4 |Reconfigure transmission system to allow Transactions using Firm |There may or may not be an Operating Security Limit| |
| |Point-to-Point Transmission Service to continue |violation. | |
|5a |Curtail Transactions (pro rata) using Firm Point-to-Point Transmission|Attempts to accommodate all Transactions using Firm|System |
| |Service to allow new Transactions using Firm Point-to-Point |Point-to-Point Transmission Service, though at a |Secure |
| |Transmission Service to begin (pro rata). |reduced (“pro rata”) level. Pro forma tariff also | |
| | |requires curtailment on pro rata basis with Network| |
| | |Integration Transmission Service and Native Load. | |
|5b |Curtail Transactions using Firm Point-to-Point Transmission Service to|Pro forma tariff requires curtailment on pro rata |Security |
| |mitigate Operating Security Limit Violation |basis with Network Integration Transmission Service|Limit |
| | |and Native Load. |Violation |
|6 |Emergency Action |Could include demand-side management, redispatch, | |
| | |voltage reductions, interruptible and firm load | |
| | |shedding | |
|0 |TLR Concluded |Restore transactions |System |
| | | |Secure |
Unless explained otherwise, “curtailment” refers to those Interchange Transactions with a 5% or greater Distribution Factor on the Constrained Facility.
Posting TLR Events
When the Security Coordinator initiates the TLR Procedure, he will notify all other Security Coordinators via the SCIS. Furthermore, the Interchange Distribution Calculator will automatically post the TLR Level on the NERC TLR Status web page.
Notification – TLR Level 1
This Level is an alert to inform the marketplace and other Security Coordinators that curtailments are likely to occur.
Hold – TLR Level 2
If an Operating Security Limit violation is imminent, the Security Coordinator shall direct his Control Areas to maintain Interchange Transactions such that, of those transactions with a 5% or greater impact on the constrained facility, only those under existing Transmission Service reservations will be allowed to continue, and only to the level existing at the time of the hold. During TLR Level 2, the Security Coordinator will allow existing Interchange Transactions to increase, or new Interchange Transactions to begin, if they help mitigate the Constraint.
TLR Level 2 is a transient state, which requires a quick decision to proceed to higher TLR Levels (3 and above) to allow Interchange Transactions to be implemented according to their transmission reservation priority. The time for being in TLR Level 2 should be no more than 30 minutes, with the understanding that there may be circumstances where this time may be exceeded. If the time in TLR Level 2a exceeds 30 minutes, the Security Coordinator must document this action on the TLR Log. When faced with a new Interchange Transaction using higher priority Point-to-Point Transmission Service, the Security Coordinator must immediately proceed to TLR Level 3a to curtail those Interchange Transactions using lower priority Point-to-Point Transmission Service. He must give preference to those Interchange Transactions using Firm Point-to-Point Transmission Service, followed by those using higher priority Nonfirm Point-to-Point Transmission Service. The Security Coordinators shall monitor and coordinate the timing of the curtailment and reallocation process.
Curtailing – TLR Levels 3a, 3b, 5a, 5b
Curtailments are required for two reasons: 1) to allow an Interchange Transaction using a higher priority Transmission Service to begin when it would otherwise cause an Operating Security Limit Violation (TLR Level 3a, and 5a); and 2) to mitigate an imminent or existing Operating Security Limit Violation (TLR Level 3b and 5b). [1]
Should curtailment become necessary to mitigate a potential or actual Operating Security Limit violation, all Interchange Transactions whose Transfer Distribution Factor (TDF) across the specific constrained facility is equal to or greater than 5% shall be curtailed whenever practicable on a proportional basis and according to these Procedures as explained in Section G, “Transaction Curtailment Formula.” The order of Interchange Transaction curtailment is explained in Section C., “Interchange Transaction Curtailment Order.”
These curtailments will remain in effect until such time as the Constraint has been mitigated, allowing the Interchange Transactions to be restored.
Reconfiguration – TLR Level 4
Before the Security Coordinator orders curtailment of Interchange Transactions using Firm Point-to-Point Transmission Service (TLR Level 5a or 5b), he will request the Transmission Providers in his Security Area to attempt to reconfigure their transmission systems to allow the Interchange Transactions to continue. Transmission reconfiguration may be implemented as long as it does not jeopardize the operating security of the Interconnection.
Emergency Procedures – TLR Level 6
If the Security Coordinator is unable to mitigate the Constraint through the use of TLR Levels 3, 4, or 5, then he has the authority to immediately direct the Control Areas to take actions such as redispatch generation, reconfigure transmission, or reduce load to mitigate the critical condition until Interchange Transactions can be reduced utilizing the TLR Interchange Transaction Curtailment Order, or other methods, to return the system to a reliable state. All Control Areas shall comply with all requests from their Security Coordinator. However, the Control Area operator should immediately notify his Security Coordinator if the Security Coordinator’s request is unclear or would seem to cause an operating problem.
Return to Normal Operations – TLR Level 0
The Security Coordinator that is experiencing the Constraint within its Security Area shall notify all Security Coordinators via the SCIS when the adverse conditions are mitigated and the system is in a “normal” state.
Considerations for Constraints On and Off the Contract Path
Interchange Transaction Priority ON the Contract Path
If the Constrained Facility is on the contract path, the curtailment priority will be equal to the Transmission Service priority of the link on which the Constrained Facility is located. [Section E., “Principles for Mitigating Constraints On and Off the Contract Path”]
Interchange Transaction Priority OFF the Contract Path
If the Constrained Facility is not on the contract path of the Interchange Transaction, the curtailment priority will be equal to the lowest Transmission Service priority of the links on the contract path. (This means that an Interchange Transaction using Firm Point-to-Point Transmission Service on all contract path links is considered a “firm” Interchange Transaction even if the Constrained Facility is off the contract path.)
Redispatch and Other Congestion Management Options
Some Transmission Providers offer redispatch or other congestion management options that allow a Transmission Customer to mitigate the effect of its Interchange Transaction on the Constrained Facility. If the Transmission Customer elects to use such an option, the Security Coordinator must treat the Interchange Transaction accordingly in the curtailment scheme. (Note: “Local” congestion management procedures require approval by NERC if they are to be used in lieu of the TLR Procedure prescription. See Policy 9.C. Requirement 3.2.1.1.)
A. General Requirements
1. Initiation only by Security Coordinator. The NERC Transmission Loading Relief Procedure may be initiated only by a Security Coordinator at 1) the Security Coordinator’s own request, or 2) upon the request of a Transmission Provider or Control Area.
2. Mitigating transmission constraints. The TLR Procedure may be used to mitigate potential or actual Operating Security Limit violations on any transmission facility modeled in the Interchange Distribution Calculator. [See also Section 6.1, “Interchange Transactions not in the IDC.]
1. Requesting relief on tie facilities. Any Transmission Provider or Control Area who operates the tie facility may request relief from his Security Coordinator.
1. Interchange Transaction priority on tie facilities. The priority of the Interchange Transaction(s) to be curtailed is determined by the Transmission Service reserved on the limiting Transmission Provider’s system who requested the relief.
3. Order of TLR Levels and taking emergency action. The Security Coordinator may not necessarily follow the TLR Levels in their numerical order (See Section B, “TLR Levels”). Furthermore, if a Security Coordinator deems that a transmission loading condition could jeopardize bulk system reliability, the Security Coordinator has the authority to enter TLR Level 6 directly, and immediately direct the Control Areas to take such actions as redispatch generation, or reconfigure transmission, or reduce load to mitigate the critical condition until Interchange Transactions can be reduced utilizing the TLR Transaction Curtailment Procedures, or other methods, to return the system to a secure state.
4. Notification of TLR Procedure implementation. The Security Coordinator initiating the use of the TLR Procedure must notify other Security Coordinators and Transmission Providers, and must post the initiation and progress of the TLR event on the NERC TLR Status web page.
1. Notifying other Security Coordinators. The Security Coordinator initiating the TLR Procedure shall inform all other Security Coordinators via the Security Coordinator Information System (SCIS) that the TLR Procedure has been implemented.
1. Actions expected. The Security Coordinator initiating the TLR Procedure shall indicate the actions expected to be taken by other Security Coordinators. [See also: Policy 3B and 3D for Control Area Requirements during curtailments.]
2. Notifying Transmission Providers and Control Areas. Security Coordinators must keep the Transmission Providers and Control Areas in his Security Area informed when entering and leaving any TLR level.
3. Notifying Control Areas. The Security Coordinator for the Sink Control Area is responsible for directing that Control Area to curtail the Interchange Transactions as specified by the Security Coordinator implementing the TLR Procedure. [See Policy 3.D. for Control Area curtailment notification details.]
1. Notification order. Within a Transmission Service priority level, the Sink Control Areas whose Interchange Transactions have the largest impact on the Constrained Facilities shall be notified first if practicable.
4. Updates. At least once each hour, or when conditions change, the Security Coordinator implementing the TLR Procedure shall update all other Security Coordinators (via the SCIS), as well as the affected Transmission Providers and Control Areas.
5. Obligations. All Security Coordinators must comply with the request of the Security Coordinator who initiated the TLR Procedure, unless the initiating Security Coordinator agrees otherwise.
1. Use of TLR Procedure with “local” procedures. A Security Coordinator may implement a local transmission loading relief or congestion management procedure simultaneously with an Interconnection-wide procedure. However, he is obligated to follow the curtailments as directed by the Interconnection-wide procedure. If the Security Coordinator desires to use a local procedure as a substitute for curtailments as directed by the Interconnection-wide procedure, he may do so only if such use is approved by the NERC Security Coordinator Subcommittee and Operating Committee.[2]
6. Consideration of Interchange Transactions. The administration of the TLR Procedure is guided by information obtained from the Interchange Distribution Calculator (IDC).
1. Interchange Transactions not in the IDC. Security Coordinators shall also treat known Interchange Transactions that may not appear in the IDC in accordance with the procedures in this document.
2. Transmission elements not in IDC. When a Security Coordinator is faced with an overload on a transmission element that is not modeled in the IDC, the Security Coordinator shall use the best information available to curtail Interchange Transactions in order to operate the system in a reliable manner. The Security Coordinator shall use his best efforts to ensure that Interchange Transactions with a Transfer Distribution Factor of less than 5% on the transmission element not modeled in the IDC are not curtailed.
3. Questionable IDC results. Any Security Coordinator (or Transmission Provider through his Security Coordinator) who believes the curtailment list from the IDC for a particular TLR event is incorrect shall use his best efforts to perform those adjustments necessary to bring the curtailment list into conformance with the principles of this Procedure. Causes of questionable IDC results may include:
• Missing Interchange Transactions that are known to contribute to the Constraint.
• Significant change in transmission system topology
• TDF matrix error.
Impacts of questionable IDC results may include:
• Curtailment that would have no effect on, or aggravate the constraint.
• Curtailment that would initiate a constraint elsewhere.
If other Security Coordinators are involved in the TLR event, there must be an agreement among those Security Coordinators on the adjustments to the curtailment list.
4. Curtailment that would cause a constraint elsewhere. If the Security Coordinator is aware that an Interchange Transaction curtailment directed by the IDC would cause a constraint to occur elsewhere, after consulting with other Security Coordinators, he may exempt that Interchange Transaction from curtailment.
5. Redispatch options. The Security Coordinator shall ensure that Interchange Transactions that are linked to redispatch options are protected from curtailment in accordance with the redispatch provisions. [See also: Policy 9C. Req. 3.2.1.1 on use of local procedures.]
7. IDC updates. Any Interchange Transaction adjustments or curtailments that result from using this Procedure must be entered into the IDC as explained in Policy 9.C. Requirement 1.1.
8. Logging. The Security Coordinator shall complete the NERC Transmission Loading Relief Procedure Log (Section H) whenever he invokes TLR Level 2 or above, and send a copy of the log via e-mail to the NERC staff within two business days of the TLR event. The staff will post these logs on the NERC web site upon receipt.
9. TLR Event Review. The Security Coordinator shall provide information regarding the TLR event to the NERC Market Interface Committee and Security Coordinator Subcommittee in accordance with TLR review processes established by NERC as required. The Market Interface Committee may conduct reviews of certain TLR events based on the size and number of Interchange Transactions that are affected, the frequency that the TLR Procedure is called for a particular Constrained Facility, or other factors. The Security Coordinator Subcommittee will conduct reviews to ensure proper implementation and for “lessons learned.”
B. Transmission Loading Relief (TLR) Levels
Introduction
This section describes the various levels of the TLR Procedure. The description of each level begins with the circumstances that define the TLR Level, followed by the procedures to be followed.
The decision that a Security Coordinator makes in selecting a particular TLR Level often depends on the transmission loading condition and whether the Interchange Transaction is using Non-firm Point-to-Point Transmission Service or Firm Point-to-Point Transmission Service. There are further considerations that depend on whether the Constrained Facility is on or off the contract path. (See Section A.6.5, “Interchange Transactions using Firm Point-to-Point Transmission Service”, and Section E., “Principles for Mitigating Constraints On and Off the Contract Path”) It is important to note, as explained in the Introduction, that an Interchange Transaction using Firm Point-to-Point Transmission Service on all contract path links is considered a “firm” Interchange Transaction even if the Constrained Facility is off the contract path.
TLR Level
s
1. Level 1 – Notify Security Coordinators of potential Operating Security Limit Violations.
1. Circumstances:
• The transmission system is secure.
• The Security Coordinator foresees a transmission or generation contingency or other operating problem within his Security Area that could cause one or more transmission facilities to approach or exceed their Operating Security Limit.
2. Notification procedures. The Security Coordinator shall notify all Security Coordinators as soon as the condition is foreseen. All affected Security Coordinators shall check to ensure that Interchange Transactions are posted in the Interchange Distribution Calculator.
2. Level 2 – Hold transfers at present level to prevent Operating Security Limit Violations
1. Circumstances for entering this level:
• The transmission system is secure,
• One or more transmission facilities are expected to approach, or are approaching, or are at their Operating Security Limit.
2. Holding procedures. The Security Coordinator may hold the implementation of any additional Interchange Transactions such that, of those transactions with a 5% or greater impact on the constrained facility, only those under existing Transmission Service reservations will be allowed to continue, and only to the level existing at the time of the hold. However, the Security Coordinator should allow additional Interchange Transactions that flow across the Constrained Facility if their flow reduces the loading on the Constrained Facility or has a Transfer Distribution Factor less than 5%.
1. TLR Level 2 is a transient state, which requires a quick decision to proceed to higher TLR Levels (3 and above) to allow Interchange Transactions to be implemented according to their transmission reservation priority. The time for being in TLR Level 2 should be no more than 30 minutes, with the understanding that there may be circumstances where this time may be exceeded. If the time in TLR Level 2a exceeds 30 minutes, the Security Coordinator must document this action on the TLR Log.
3. Level 3a – Curtail Interchange Transactions using Non-firm Point-to-Point Transmission Service to allow Interchange Transactions using higher priority Point-to-Point Transmission Service.
1. Circumstances for entering this level:
• The transmission system is secure
• One or more transmission facilities are expected to approach, or are approaching, or are at their Operating Security Limit
• All new Interchange Transaction requests with a 5% or greater TDF over the Constrained Facility are being held.
• The Transmission Provider has previously approved a higher priority Point-to-Point Transmission Service reservation over which a Transmission Customer wishes to begin an Interchange Transaction.
2. Curtailment procedures to allow Interchange Transactions using higher priority Point-to-Point Transmission Service. At the request of the Sink Control Area via its Security Coordinator, the Security Coordinator with the constraint shall give preference to those to Interchange Transactions using Firm Point-to-Point Transmission Service, followed by those using higher priority Nonfirm Point-to-Point Transmission Service as specified in Section C. “Interchange Transaction Curtailment Order.”
4. Level 3b – Curtail Interchange Transactions using Non-Firm Transmission Service Arrangements to mitigate an Operating Security Limit Violation
1. Circumstances for entering this level:
• One or more Transmission Facilities are operating above their Operating Security Limit, or
• Such operation is imminent and it is expected that facilities will exceed their security limit unless corrective action is taken, or
• One or more Transmission Facilities will exceed their Operating Security Limit upon the removal from service of a generating unit or another transmission facility
2. Holding new Interchange Transactions. The Security Coordinator shall hold all new Interchange Transactions with a 5% or greater TDF over the Constrained Facility during the period of the Operating Security Limit Violation.
3. Curtailment procedures to mitigate an Operating Security Limit. The Security Coordinator shall curtail Interchange Transactions using Non-firm Point-to-Point Transmission Service with a 5% or greater TDF over the Constraints as specified in Section C. “Interchange Transaction Curtailment Order.”
5. Level 4 – Reconfigure Transmission
1. Circumstances for entering this level:
• One or more Transmission Facilities are above their Operating Security Limit, or
• Such operation is imminent and it is expected that facilities will exceed their security limit unless corrective action is taken
• All Interchange Transactions using Non-firm Point-to-Point Transmission Service have been curtailed.
2. Reconfiguration procedures. Following the curtailment of all Interchange Transactions using Non-firm Point-to-Point Transmission Service in Level 3b above that impact the Constrained Facilities, if an Operating Security Limit violation is imminent or occurring, the Security Coordinator(s) shall request that the affected Transmission Providers reconfigure transmission on their system, or arrange for reconfiguration on other transmission systems, to mitigate the constraint. Specific details are explained in Section E., “Principles for Mitigating Constraints On and Off the Contract Path.”
6. Level 5a – Curtail Interchange Transactions using Firm Point-to-Point Transmission Service on a pro rata basis to allow additional Interchange Transactions using Firm Point-to-Point Transmission Service.
1. Circumstances:
• The transmission system is secure
• One or more transmission facilities are at their Operating Security Limit
• All Interchange Transactions using Non-firm Point-to-Point Transmission Service with a 5% or greater TDF over the Constrained Facilities have been curtailed.
• The Transmission Provider has been requested to begin an Interchange Transaction using previously arranged Firm Transmission Service that would result in an Operating Security Limit Violation.
• No further transmission reconfiguration is possible or effective.
2. Curtailment Procedures. Curtailment of Interchange Transactions using Firm Point-to-Point Transmission Service is a three-step process as follows:
1. Step 1 – Identify available redispatch options. The Security Coordinator shall assist the Transmission Provider(s) in identifying whatever redispatch options are available to the Transmission Customer that will mitigate the loading on the Constrained Facilities. If such redispatch options are deemed insufficient to mitigate loading on the Constrained Facilities, the Security Coordinator shall proceed to implement these options while proceeding to Steps 2 and 3 below.
2. Step 2 – Calculate percent of the overload on the Constrained Facility due to Interchange Transactions using Firm Point-to-Point Transmission Service with a 5% or greater TDF. This is the MW that can be curtailed using the TLR Procedure, and this value shall be communicated to the Transmission Provider with the constraint. This is described in Section F, “Transaction Contribution Factor Calculation.” The Security Coordinator shall assist the Transmission Provider to calculate the percent of the overload on the Constrained Facilities caused by the Transmission Provider’s Network Integration Transmission Service and Native Load as required by the Transmission Provider’s filed tariff.
3. Step 3 – Curtail Interchange Transactions using Firm Transmission Service. The Security Coordinator shall curtail on a pro-rata basis (based on the MW level of the MW total to all such Interchange Transactions), those Interchange Transactions as calculated in Section 7.2.2 over the Constrained Facilities. The Security Coordinator shall assist the Transmission Provider in curtailing Transmission Service to Network Integration Transmission Service customers and Native Load if such curtailments are required by the Transmission Provider’s tariff. Available redispatch options will continue to be implemented.
7. Level 5b – Curtail Interchange Transactions using Firm Point-to-Point Transmission Service to mitigate an Operating Security Limit Violation.
1. Circumstances:
• One or more Transmission Facilities are operating above their Operating Security Limit, or
• Such operation is imminent, or
• One or more Transmission Facilities will exceed their Operating Security Limit upon the removal from service of a generating unit or another transmission facility.
• All Interchange Transactions using Non-firm Point-to-Point Transmission Service with a 5% or greater TDF over the Constrained Facilities have been curtailed.
• No further transmission reconfiguration is possible or effective.
2. Curtailment of Interchange Transactions using Firm Point-to-Point Transmission Service is a three-step process as follows:
1. Step 1 – Identify available redispatch options. The Security Coordinator shall assist the Transmission Provider(s) in identifying whatever redispatch options are available to the Transmission Customer that will mitigate the loading on the Constrained Facilities. If such redispatch options are deemed insufficient to mitigate loading on the Constrained Facilities, the Security Coordinator shall proceed to implement these options while proceeding to Steps 2 and 3 below.
2. Step 2 – Calculate Transaction Contribution Factor. The Security Coordinator shall calculate the percent of the overload on the Constrained Facility due to Interchange Transactions using Firm Point-to-Point Transmission Service with a 5% or greater TDF. This is the MW that can be curtailed using the TLR Procedure, and this value shall be communicated to the Transmission Provider with the constraint. This is described in Section F, “Transaction Contribution Factor Calculation.” If required by the Transmission Providers’ tariffs, the Security Coordinator shall assist the Transmission Provider calculate the percentage of the overload on the Constrained Facilities caused by the Transmission Provider’s Network Integration Transmission Service and Native Load.
3. Step 3 – Curtailment of Interchange Transactions using Firm Transmission Service. At this point, the Security Coordinator shall begin the process of curtailing Interchange Transactions as calculated in Section 7.2.2 over the Constrained Facilities using Firm Point-to-Point Transmission Service until the Operating Security Limit violation has been mitigated. The Security Coordinator shall assist the Transmission Provider in curtailing Transmission Service to Network Integration Transmission Service customers and Native Load if such curtailments are required by the Transmission Providers’ tariff. Available redispatch options will continue to be implemented.
8. Level 6 – Emergency Procedures
1. Circumstances:
• One or more Transmission Facilities are above their Operating Security Limit.
• One or more Transmission Facilities will exceed their Operating Security Limit upon the removal from service of a generating unit or another transmission facility.
2. Implementing emergency procedures. If the transmission loading condition is deemed critical to bulk system reliability by a Security Coordinator, the Security Coordinator has the authority to immediately direct the Control Areas in his Security Area to redispatch generation, or reconfigure transmission, or reduce load to mitigate the critical condition until Interchange Transactions can be reduced utilizing the TLR Procedures or other procedures to return the system to a secure state. All Control Areas shall comply with all requests from their Security Coordinator.
9. Level 0 – TLR concluded
1. Interchange Transaction restoration and notification procedures. The Security Coordinator initiating the TLR Procedure shall notify all Security Coordinators within the Interconnection via the SCIS when the Operating Security Limit violations are mitigated and the system is in a “normal” state, allowing Interchange Transactions to be reestablished at his discretion. Those with the highest transmission priorities shall be reestablished first if possible.
C. Interchange Transaction Curtailment Order
Curtailment of Interchange Transactions Using Non
-firm Transmission Service
The Security Coordinator will direct the curtailment of Interchange Transactions using Non-firm Transmission Service and whose Transfer Distribution Factor (TDF) over the Constrained Facilities is 5% or greater for the following TLR Levels:
1. TLR Level 3a. Enable Interchange Transactions using a higher Transmission reservation priority to be implemented, or
2. TLR Level 3b. Mitigate an Operating Security Limit violation.
The Interchange Transaction curtailment priority is determined by its Transmission Service reservation over the constrained facility(ies) as shown in the box on the right:
The curtailment priority for Interchange Transactions that do not have a Transmission Service reservation over the constrained facility(ies) is the lowest priority of the individual reserved transmission segments.
Curtailment of Interchange Transactions Using Firm Transmission Service
The Security Coordinator will direct the curtailment of Interchange Transactions using Firm Transmission Service and whose TDF over the Constrained Facilities is 5% or greater for the following TLR Levels:
1. TLR Level 5a. Enable additional Interchange Transactions using Firm Point-to-Point Transmission Service to be implemented after all Interchange Transactions using Non-firm Point-to-Point Service have been curtailed, or
2. TLR Level 5b. Mitigate an Operating Security Limit violation that remains after all Interchange Transactions using Non-firm Transmission Service has been curtailed under TLR Level 3b, and following attempts to reconfigure transmission under TLR Level 4.
A. D. Transaction Management and Curtailment Process
This flowchart depicts an overview of the Transaction Management and Curtailment process. Detailed decisions are not shown.
E. Principles for Mitigating Constraints On and Off the Contract Path
Introduction
Reserving transmission service for an Interchange Transaction along a “contract path” may not reflect the actual distribution of the power flows over the transmission network from generation source to load sink. Interchange Transactions arranged over a contract path may, therefore, overload transmission elements on other electrically parallel paths. The Security Coordinators must agree on how the NERC Transmission Loading Relief Procedure will handle these Interchange Transactions to, first, ensure the operational security of the Interconnection and, second, respect the obligations of the Transmission Providers’ tariffs.
The curtailment priority of an Interchange Transaction depends on whether the Constrained Facility is on or off the contract path, and, if on the contract path, the Transmission Service of the link with the Constrained Facility.
The Security Coordinator must also consider 1) the tariff obligations of the Transmission Provider with the Constrained Facility, 2) the Transmission Customer’s redispatch or other congestion management arrangements, and 3) arrangements among the Transmission Providers for handling certain Constraints. Refer to examples beginning on page A9C1-343280.
Principles for Constraints ON the Contract Path
1. If the transmission link with the Constrained Facility is Non-firm Point-to-Point Transmission Service, the entire Interchange Transaction is considered non-firm, even if other links in the contract path are firm. When the Constrained Facility is on the contract path, the Interchange Transaction takes on the transmission service priority of the Transmission Service link with the Constrained Facility regardless of the Transmission Service priority on the other links along the contract path.
Discussion. The Transmission Provider simply has to call its Security Coordinator, request the TLR Procedure be initiated, and allow the curtailments of all Interchange Transactions using Non-firm Point-to-Point Transmission Service with a 5% or greater TDF to progress until the relief is realized. Firm Point-to-Point Transmission Service links elsewhere in the contract path do not obligate Transmission Providers providing Non-firm Point-to-Point Transmission Service to treat the transaction as firm. For curtailment purposes, the Interchange Transaction’s priority will be the priority of the Transmission Service link with the Constrained Facility. (See Principle #2 below.)
2. If the transmission link with the Constrained Facility is Firm Point-to-Point Transmission Service, the entire Interchange Transaction is considered firm, even if other links in the contract path are non-firm.
Discussion. The curtailment priority of an Interchange Transaction on a contract path link is not affected by the transmission service priorities arranged with other links on the contract path. If the Constrained Facility is on a Firm Point-to-Point Transmission Service contract path link, then the curtailment priority of the Interchange Transaction is considered firm regardless of the transmission service arrangements elsewhere on the contract path. If the Transmission Provider provides its services under the FERC pro forma tariff, it may also be obligated to offer its Transmission Customer alternate receipt and delivery points, thus allowing the Customer to curtail its Transmission Service over the Constrained Facilities.
For Constraints OFF the Contract Path
3. If any of the transmission links on the contract path are Non-firm Point-to-Point Transmission Service, the Interchange Transaction is considered non-firm by the system with the Constrained Facility that is not on the contract path, and takes on the lowest transmission service priority of all Transmission Service links along the contract path.
Discussion. An Interchange Transaction arranged over a contract path where one or more individual links consist of Non-firm Point-to-Point Transmission Service is considered to be a non-firm Interchange Transaction for Constrained Facilities off the contract path. Sufficient Interchange Transactions with a 5% or greater TDF over the Constrained Facility will be curtailed before any Interchange Transactions using Firm Point-to-Point Transmission Service are curtailed. The priority level for curtailment purposes will be the lowest level of transmission service arranged for on the contract path.
4. If all of the transmission links on the contract path with the Constrained Facility are Firm Point-to-Point Transmission Service, then the Interchange Transaction is considered firm and will not be curtailed to relieve a Constraint off the contract path until all non-firm Interchange Transactions with a 5% or greater TDF over the Constraint have been curtailed.
Discussion. If the entire contract path is Firm Point-to-Point Transmission Service, then the TLR procedure will treat the Interchange Transaction as firm even for Constraints off the contract path and will not curtail that Interchange Transaction until all non-firm Interchange Transactions with a 5% or greater TDF have been curtailed. However, Transmission Providers off the contract path are not obligated to reconfigure their transmission system or provide other congestion management procedures unless special arrangements are in place. Because the Interchange Transaction is considered firm “everywhere,” the Security Coordinator may attempt to arrange for Transmission Providers or Control Areas to reconfigure transmission or provide other congestion management options, even if they are off the contract path, to try to avoid curtailing the Interchange Transaction that is using the Firm Point-to-Point Transmission Service.
Examples
This section explains, by example, the obligations of the Transmission Providers on and off the contract path when calling for Transmission Loading Relief. (References to Principles refer to Section E, “Principles for Mitigating Constraints On and Off the Contract Path,” on the preceding pages.)
Scenario:
• Interchange Transaction arranged from system A to system D, and assumed to have at least a 5% TDF across the Constraint(s).
• Contract path is A-E-C-D (except as noted)
• Locations 1 and 2 denote Constraints
3
Case 1: E is a non-firm Monthly path, C is non-firm Hourly; E has Constraint at #2.
• E may call Security Coordinator for TLR Procedure to relieve overload at Constraint #2.
• Interchange Transaction A-D may be curtailed by TLR action as though it was being served by Non-firm Monthly Point-to-Point Transmission Service, even though it was using Non-firm Hourly Point-to-Point Transmission Service from C. That is, it takes on the priority of the link with the Constrained Facility along the contract path. (Principle 1)
5
Case 2: E is a non-firm hourly path, C is firm; E has Constraint at #2.
• Although C is providing Firm Service, the Constraint is not on C’s system, therefore C is not obligated to treat the Interchange Transaction as though it was being served by Firm Point-to-Point Transmission Service.
• E may call Security Coordinator for TLR Procedure to relieve overload at Constraint #2.
• Interchange Transaction A-D may be curtailed by TLR action as though it was being served by Non-firm Hourly Point-to-Point Transmission Service, even though it was using firm service from C. That is, when the constraint is on the contract path, the Interchange Transaction takes on the priority of the link with the Constrained Facility. (Principle 1)
7
Case 3: E is a non-firm hourly path, C is firm, B has Constraint at #1.
• B may call Security Coordinator for TLR Procedure to relieve overload at Constraint #1.
• Interchange Transaction A-D may be curtailed by TLR action as though it was being served by Non-firm Hourly Transmission Service, even if it was using firm Transmission Service elsewhere on the path. When the constraint is off the contract path, the Interchange Transaction takes on the lowest priority reserved on the contract path. (Principle 3)
9
Case 4: E is a firm path; A, D, and C are Non-firm; E has Constraint at #2.
• Interchange Transaction A – D is considered Firm priority for curtailment purposes.
• E may then call Security Coordinator for TLR, which would curtail all Interchange Transactions using Non-firm Point-to-Point Transmission Service first.
• E is obligated to reconfigure transmission to mitigate Constraint #2 in E before E may curtail the Interchange Transaction as ordered by the TLR. (Principle 2)
Case 5: The entire path (A-E-C-D) is firm; E has Constraint at #2.
• Interchange Transaction A – D is considered Firm priority for curtailment purposes.
• E may call Security Coordinator for TLR, which would curtail all Interchange Transactions using Non-firm Point-to-Point Transmission Service first.
• E is obligated to curtail Interchange Transactions using Non-firm Point-to-Point Transmission Service, and then reconfigure transmission on its system, or, if there is an agreement in place, arrange for reconfiguration or other congestion management options on another system, to mitigate Constraint #2 in E before the firm A-D transaction is curtailed. (Principle 2)
• A, C, D, may be requested by E to reconfigure transmission to mitigate Constraint #2 in E at E’s expense. (Principle 2)
13
Case 6: The entire path (A-E-C-D) is firm; B has
( Interchange Transaction A – D is considered Firm priority for curtailment purposes.
• B may call Security Coordinator for TLR Procedure for all non-firm Interchange Transactions that contribute to the overload at Constraint #1.
• Following the curtailment of all non-firm Interchange Transactions, the Security Coordinator(s) will determine which Control Area(s) will reconfigure their transmission to mitigate constraint #1. (Principle 4)
• A-D transaction may be curtailed as a result. However, the A-D transaction is treated as a firm Interchange Transaction and will be curtailed only after non-firm Interchange Transactions. (Note: This means that the firm contract path is respected by all parties, including those not on the contract path.) (Principle 4)
16
Case 7: Two A-to-D transactions using A-B-C-D and A-E-C-D; A and B are non-firm; B has Constraint at #1
• B is not obligated to reconfigure transmission to mitigate Constraint at #1. (Principle 1)
• B may call for TLR Procedure to relieve overload at Constraint #1.
• If both A – D Interchange Transactions have the same TDF (5% or greater) across Constraint #1, then they both are subject to curtailment. However, Interchange Transaction A – D using the A-B-C-D path is assigned a higher priority (priority NW on B), and would not be curtailed until after the Interchange Transaction using the path A-E-C-D (priority NH on the contract path as observed by B who is off the contract path).
F. Transaction Contribution Factor Calculation
Introduction
This section is intended to explain how to calculate the flows over the Constrained Facility due to Transactions using Firm Point-to-Point Transmission Service. It is not intended to specify how to calculate the effects of Network Integration Transmission Service and service to Native Load, nor the calculation of the effects of flows from Interchange Transactions with less than 5% Transfer Distribution Factor.
There are two situations that may require the curtailment of Interchange Transactions using Firm Point-to-Point Transmission Service. In both situations, all Interchange Transactions using Non-firm Point-to-Point Transmission Service have been curtailed:
1. An Interchange Transaction with Firm Point-to-Point Transmission Service is scheduled to start, but doing so would cause an Operating Security Limit Violation, and there are no Interchange Transactions using Non-firm Point-to-Point Transmission Service that can be curtailed to mitigate this potential overload. TLR Level 5a is declared to allow additional Interchange Transactions using Firm Point-to-Point Transmission Service to begin on a pro rata basis, with corresponding pro rata curtailments of other Interchange Transactions using Firm Point-to-Point Transmission Service.
2. In the second case, an Operating Security Limit Violation already exists, and all Interchange Transactions using Non-firm Point-to-Point Transmission Service have been curtailed. TLR Level 5b is declared to curtail the necessary Interchange Transactions using Firm Point-to-Point Transmission Service to mitigate the Operating Security Limit.
In both cases, the Transmission Provider may be obligated to perform comparable curtailments of its Network Integration Transmission Service and Native Load customers. Therefore, the Transmission Provider needs to consider what percent of the overload on the Constrained Facility is due to each of these types of Transmission Services.
Calculating Flows Due to Firm Point-to-Point Transmission Service
When entering TLR Level 5a or 5b, the Transmission Provider first provides the Security Coordinator with the total MW flow on the Constrained Facility. The Security Coordinator then interrogates the Interchange Distribution Calculator to determine the total MW flow over the Constrained Facility from Interchange Transactions (inter-Control Area) using Firm Point-to-Point Transmission Service. Next, the Transmission Provider adds the MW flow over the Constrained Facility from intra-Control Area Transactions on its system using Firm Point-to-Point Transmission Service. The sum of these two values is the Transaction Contribution due to Firm Point-to-Point Transmission Service, or TCptp, that have a Distribution Factor greater than 5%.
Calculating the Transaction Contribution Factor for Firm Point-to-Point Transmission Service
Dividing the Transaction Contribution due to Firm Point-to-Point Transmission Service by the total flow over the Constrained Facility yields the Transaction Contribution Factor for Firm Point-to-Point Transmission Service, or TCFptp.
Calculating the Curtailment Ratios for all Firm Transmission Services
After considering the TCptp, the remaining flows over the Constrained Facility must therefore be due to inter- and intra-Control Area generation-to-load flows using Firm Network Integration Transmission Service and Native Load Service, including parallel flows from other Control Areas, parallel flows due to intra-Control Area Transactions using Firm Point-to-Point Transmission service on adjacent systems, as well as those Interchange Transactions below the 5% Distribution Factor threshold that were not curtailed, plus other flows from unknown sources. The example that follows illustrates these various component flows over the Constrained Facility.
It is up to the Transmission Provider to allocate the curtailment of these remaining flows among its Transmission Customers, which will include adjustments to its TCFptp factor, according to its transmission tariff or Regional procedures. Refer to the example on page 350 363..
Example
• Facility XYZ has an Operating Security Limit of 900 MW.
• Its current metered flow is 1,100 MW, or 200 MW over the Operating Security Limit.
• All non-firm transactions eligible for curtailment have been curtailed.
Remaining flows over the Constrained Facility are:
• 700 MW due to parallel flows from Firm Network Integration Transmission and Native Load Service in Control Areas A, B, and C.
• 50 MW due to Interchange Transactions using non-Firm Transmission Service with a distribution factor below the 5% curtailment threshold.
• 50 MW due to unknown reasons.
The IDC shows that the contribution from the Firm and remaining Non-Firm Transactions contributing to the loading on this flowgate for hour ending 1600 (starting at 1500 hours) is 300 MW.
G. Transaction Curtailment Formula
Example
This example is based on the premise that a transaction should be curtailed in proportion to its TDF on the Constraints. Its effect on the interface is a combination of its size in MW and its effect based on its distribution factor.
|Column |Description |
|1. Initial Transaction |Interchange Transaction before the TLR Procedure is implemented. |
|2. Distribution Factor |Proportional effect of the Transaction over the constrained interface due to the |
| |physical arrangement and impedance of the transmission system. |
|3. Impact on the Interface |Result of multiplying the Transaction MW by the distribution factor. This yields the |
| |MW that flow through the constrained interface from the Transaction. Performing this |
| |calculation for each Transaction yields the total flow through the constrained |
| |interface from all the Interchange Transactions. In this case, 760 MW. |
|4. Impact Weighting Factor |“Normalization” of the total of the Distribution Factors in Column 2. Calculated by |
| |dividing the Distribution Factor for each Transaction by the total of the Distribution|
| |Factors. |
|5. Weighted Maximum Interface Reduction |Multiplying the Impact on the Interface from each Transaction by its Impact Weighting |
| |Factor yields a new proportion that is a combination of the MW Impact on the Interface|
| |and the Distribution Factor. |
|6. Interface Reduction |Multiplying the amount we need to reduce the flow over the constrained interface (280 |
| |MW) by the normalization of the Weighted Maximum Interface Reduction yields the actual|
| |MW reduction that each Transaction must contribute to achieve the total reduction. |
|7. Transaction Reduction |Now we have to divide by the Distribution Factor to see how much the Transaction must |
| |be reduced to yield the result we calculated in Column 7. Note that the reductions for|
| |the first two Interchange Transactions (A-D (1) and A-D (2) are in proportion to their|
| |size since their distribution factors are equal. |
|8. New Transaction Amount |Subtracting the Transaction Reduction from the Initial Transaction yields the New |
| |Transaction Amount. |
|9. Adjusted Impact on Interface |A check to ensure the new constrained interface MW flow has been reduced to the target|
| |amount. |
H. NERC Transmission Loading Relief Procedure Log
ATTACHMENT P – Generator Interconnections
Preamble
An Interconnection Customer that proposes to interconnect a new generating facility to the Transmission System or to increase the capacity of an existing generating facility connected to the Transmission System, shall follow the terms, conditions and procedures set forth in this Attachment P to the Open Access Transmission Tariff (Tariff) and pay for any Direct Assignment Facilities including a gross-up for the income tax effects, if any, of such payments. Direct Assignment Facilities are: (a) the facilities necessary to physically and electrically interconnect the generating facility to the Transmission System and (b) the minimum necessary local and network upgrades that would not have been incurred but for such Interconnection Requests, including (i) system upgrades necessary to remove overloads and (ii) system upgrades necessary to remedy short-circuit or stability problems resulting from the connection of the generating facility to the network. Direct Assignment Facilities shall not include system upgrades that may be required to move power from the point of interconnection to load. The Interconnection Request is required for all generating facilities regardless of the type or size of the generation, or whether the interconnection is made at transmission or distribution voltage.
The terms, conditions and procedures set forth in this Attachment P shall apply only to the extent that generator interconnection procedures of The Electric Reliability Council of Texas or the Southwest Power Pool do not apply, in the AEP West Zone, or the Alliance RTO, in the AEP East Zone.
1. Generator Interconnection Requests
1.1 Interconnection Request: An Interconnection Customer shall submit to the Transmission Provider, an Interconnection Request in the form of Attachment Q (Notification of Intent to Install and Operate Generation Interconnected with the AEP Transmission System.) An Interconnection Request shall include: (a) the location of the proposed new generating facility site or existing generating facility site; (b) the size of the proposed new generating facility or the amount of increase in the generation capacity at an existing generating facility; (c) a one-line diagram describing the basic electrical connection; (d) a statement as to whether the capacity addition is base load, intermediate, or peaking; (e) the planned in-service date for the proposed generating units; and (f) a deposit of $10,000. The deposit will be applied toward the cost of a System Impact Study. The Transmission Provider shall refund to the Interconnection Customer, with interest, any portion of the deposit that exceeds the cost of the System Impact Study. The Interconnection Customer must submit a separate Generation Interconnection Request for each site.
1.2 Tender of Interconnection and Operation Agreement. Within seven (7) days of its receipt of a completed Interconnection Request, the Transmission Provider shall tender a Interconnection and Operation Agreement to the Interconnection Customer. The Interconnection and Operation Agreement will cover issues generally addressed in such agreements in accordance with Good Utility Practice, including construction of facilities, system operation, interconnection cost and billing, defaults and remedies, insurance and liability,etc. Pursuant to the Facility Interconnection and Operation Agreement, an Interconnection Customer shall agree to reimburse the Transmission Provider for the full cost of Direct Assignment Facilities. The Interconnection Customer shall be entitled to a credit for a portion of such payments, as described in Section 3.2 of this Attachment.
1.3 System Impact Study: Within seven (7) days of its receipt of a completed Interconnection Request, the Transmission Provider shall provide to the Interconnection Customer a System Impact Study Agreement. The System Impact Study Agreement will include the scope of the System Impact Study. Pursuant to the System Impact Study Agreement, the Interconnection Customer shall agree to reimburse the Transmission Provider for the total cost of the System Impact Study if it exceeds the deposit. The System Impact Study Agreement shall specify: (a) the Transmission Provider’s estimate of the cost of, and the time estimated to complete, each phase of the System Impact Study and (b) the relevant technical data that must be provided by the Interconnection Customer for the study.
1.4 Scope of System Impact Study: The System Impact Study will be conducted to evaluate whether system upgrades are needed to accept power into the grid at the interconnection receipt point. The System Impact Study will be conducted in two phases. Phase 1 will include a power flow analysis and Phase 2 will include short circuit and stability analyses. The power flow analysis, at a minimum, will examine the impact on transmission facilities due to the proposed generation addition. The short circuit analysis will evaluate the impact of the proposed generation addition on the short circuit capability of the circuit breakers at the interconnection point and at nearby stations. The stability study will be carried out: (a) to assess the ability of the proposed generation facility to remain in synchronism following credible system events, including faults; (b) to assess the adequacy of damping of generation/transmission oscillations; and (c) to evaluate the impact on stability performance of existing generators in the vicinity. The study criteria that the Transmission Provider uses in the System Impact Study is documented in the Transmission Provider’s FERC Form 715 filing. The Form 715 criteria are set forth in Attachment R. In conducting a System Impact Study, the Transmission Provider shall utilize existing studies to the extent practicable.
Ordinarily, Phase 2 of a System Impact Study can be started prior to the completion of Phase 1; however, an Interconnection Customer may choose to have Phase 1 and Phase 2 performed sequentially, as a means of segmenting its decision-making and potentially reducing its costs.
In cases involving generators of 5 MW or less, deposit requirements may be reduced by the Transmission Provider, to account for the reduced scope of study necessary in such cases. Any such reduction in deposit requirements shall be applied by the Transmission Provider on a non-discriminatory basis to all Interconnection Customers, including those affiliated with the Transmission Provider. Because of their limited scope, such studies may be initiated and completed in less time than is otherwise provided for in this Attachment P to the Tariff for System Impact Studies and Facilitiesy Studies.
1.5 Posting of Interconnection Requests on OASIS: The Transmission Provider will maintain on its OASIS a list of all Interconnection Requests. The list will identify the size in Megawatts of each request, location of the generation and the station or a transmission line(s) where the proposed generation is likely to be connected. This list will not disclose the identity of the Interconnection Customer.
1.6 System Impact Study Agreement: The Interconnection Customer shall execute the System Impact Study Agreement within fifteen (15) days of its receipt and provide to the Transmission Provider an additional $7,500 deposit if the Interconnection Customer elects to have both phases of the Study performed.
1.7 System Impact Study Procedures: Upon receipt of an executed System Impact Study Agreement, along with the required deposit and all relevant technical data for completing the study, the Transmission Provider will use due diligence to start the required System Impact Study within forty-five (45) days and to complete the required System Impact Study within sixty (60) days from the date it is started. In the event that the Transmission Provider is unable to start or to complete the required System Impact Study within such time period, it shall so notify the Interconnection Customer and provide an estimated start date or completion date along with an explanation of the reasons why additional time is required to start or complete the required studies. The Interconnection Customer’s election to have Phase 1 and Phase 2 of the System Impact Study performed sequentially is likely to extend the time necessary to complete the full System Impact Study. The Transmission Provider will use the same due diligence in completing the System Impact Study for all Eligible Customers, including its affiliates, as it uses when completing studies for itself.
1.8 Completion of System Impact Study: Upon completion of each phase of the System Impact Study, a report documenting the results of the Study will be provided to the Interconnection Customer. The System Impact Study will identify the potential problems determined based on power flow, short circuit and stability analyses. However, if the Interconnection Customer has requested that Phase 1 and Phase 2 of the System Impact Study be performed sequentially, then the initial report shall show only the results of the power flow analysis. The Interconnection Customer may request the Transmission Provider to proceed to conduct the Phase 2 Study by initialing the System Impact Study Agreement and providing an additional $7,500 deposit.
1.9 Posting on OASIS: Upon completion of Phase 1 and Phase 2 of the System Impact Study, the Transmission Provider will update its OASIS showing the completion of the System Impact Study. A brief summary of the study results for each Interconnection Request will also be posted on the OASIS. The summary shall include information about all substantial system upgrades and problems that are identified in the System Impact Study.
1.10 Scope of Facilities Study: If the Interconnection Customer elects to proceed, a Facilities Study will be carried out to determine the details of the physical connection between the network and proposed generating facility and to address the reliability problems identified in the System Impact Study. The electrical switching configuration of the connection equipment including transformer switch gear and other station equipment, and required transmission lines (if any) will be determined as part of the Facilities Study. Good faith cost estimates for the Direct Assignment Facilities necessary to accommodate the interconnection request and the time required to complete construction of such facilities will also be provided as part of the Facilities Study.
1.11 Facilities Study Agreement: The Transmission Provider, upon completion of the System Impact Study, shall tender to the Interconnection Customer a Facilities Study Agreement. The Interconnection Customer must provide to the Transmission Provider an executed Facilities Study Agreement within twenty-one (21) days of the receipt of the Facilities Study Agreement and provide an additional deposit of $12,500. This deposit will be applied toward the cost of the Facilities Study. Pursuant to the Facilities Study Agreement, the Interconnection Customer will reimburse the Transmission Provider for the unpaid cost of the Facilities Study if the cost of the study exceeds the deposit. The Transmission Provider shall refund to the Interconnection Customer, with interest, any portion of the deposit that exceeds the cost of the Facilities Study. If the executed Agreement is not received within twenty-one (21) days, the priority assigned in the queue will be lost.
1.12 Letter Agreement: Upon the Interconnection Customer’s execution of a Facilities Study Agreement, the Transmission Provider shall provide, if requested, to the Interconnection Customer a Letter Agreement which authorizes the Transmission Provider to begin engineering and design activities and procurement of long lead-time items necessary for the establishment of the interconnection. The Letter Agreement will require the Interconnection Customer to pay the cost of all activities authorized by the Interconnection Customer and to make advance payments or provide other satisfactory security. The Interconnection Customer shall pay the cost of such activities and cancellation costs for equipment that is already ordered for the project whether or not such items or equipment later become unnecessary. No construction activities shall be undertaken until after an Interconnection and Operation Agreement is executed or an unexecuted Interconnection and Operation Agreement is filed pursuant to Section 1.13.
1.13 Facilities Study Procedures: Upon receipt of an executed Facilities Study Agreement, the Transmission Provider will use due diligence to complete the required Facilities Study within sixty (60) days. If the Transmission Provider is unable to complete the Facilities Study in the allotted time, the Transmission Provider shall notify the Interconnection Customer and provide an estimate of the time needed to reach a final determination along with an explanation of the reasons that additional time is required to complete the study. When completed, the Facilities Study will include a good faith estimate of the Direct Assignment costs to be charged to the Interconnection Customer and the time required to complete construction and initiate the requested service.
1.14 Posting on OASIS: Upon completion of the Facilities Study, the Transmission Provider will update its OASIS showing the completion of the Facilities Study. The OASIS posting will include a brief summary of the interconnection and network upgrade facilities needed to accommodate the requested interconnection of the proposed generation into the Transmission System.
1.15 Retaining Priority: To retain the assigned priority of its Interconnection Request, within twenty-one (21) days of the receipt of the Facilities Study Report or one hundred twenty (120) days following the Transmission Provider’s tender of the Interconnection and Operation Agreement, whichever is later, but in no event sooner than its receipt of the Facilities Study Report, the Interconnection Customer must execute and return the tendered Interconnection and Operation Agreement, or request the filing of an unexecuted Interconnection and Operation Agreement. If the Interconnection Customer requests the filing of an unexecuted Agreement, it must agree to abide by all of the terms of the Agreement except as may later be modified by the Commission. The Interconnection Customer must also provide to the Transmission Provider a letter of credit or other reasonable form of security acceptable to the Transmission Provider to assure the Transmission Provider’s recovery of Direct Assignment costs.
1.16 Withdrawal: If the Interconnection Customer fails to execute the Interconnection and Operation Agreement or request filing of an unexecuted Interconnection and Operation Agreement or fails to provide the necessary security prescribed in accordance with Section 1.15, its Interconnection Request shall be deemed to be terminated. An Interconnection Customer may withdraw its Interconnection request at any time provided that the Interconnection Customer shall pay to the Transmission Provider all costs prudently incurred by the Transmission Provider prior to the Transmission Provider’s receipt of notice of such withdrawal.
1.17 Filing of Interconnection and Operation Agreement and Commencement of Construction: The Transmission Provider shall file the Interconnection and Operation Agreement with FERC in compliance with applicable Commission regulations. The Transmission Provider and the Interconnection Customer shall be responsible for obtaining all permits, licenses, and necessary authorizations to comply with any applicable federal, state or local laws. Each party shall cooperate with the other in obtaining any such permits, licenses and necessary authorizations for the construction of facilities necessary for establishment of the interconnection.
1.18 Queue Priority: Except as provided in Section 2, queue priority for the purpose of performance of the necessary studies, for the interconnection and for cost responsibility for upgrades shall be based upon the date of the Transmission Provider’s receipt of a completed Interconnection Request so long as all other deadlines provided for in this Attachment are met by the Customer. Such priority is subject to the cost sharing provisions of Section 1.19.
1.19 Any Interconnection Customer who has signed an Interconnection and Operation Agreement may request the Transmission Provider to conduct a study, at the requesting Customer’s expense, to determine whether one or more other Interconnection Customer(s) who has signed an Interconnection and Operation Agreement should share direct assignment cost responsibility for common upgrades. Such cost sharing shall not be found appropriate unless the Interconnection Requests in question were submitted within one year of one another. Upgrades shall be considered common when each of the generating facilities, independent of the other(s), would have required the upgrades or when upgrades are required as a result of the combination of the upgrades required for each of the generating facilities. If the studies find that common upgrades exist, and sharing is otherwise appropriate under this section, each Interconnection Customer’s responsibility for direct assignment of system upgrade costs shall be adjusted to reflect the appropriate sharing. If one Customer has already made payments of more than its share, the other(s) shall reimburse the paying customer. Costs shall be shared in proportion to the maximum capability of each affected Customer’s generating facility, unless otherwise agreed by the Customers.
1.20 Confidentiality: Until completion of each study required under this Attachment P to the Tariff, the Transmission Provider shall keep confidential all information that was provided by the Interconnection Customer relating to such study. However, upon completion of each study, a summary of the study will be listed on the Transmission Provider’s OASIS and made publicly available, to the extent required by Commission regulations.
2. Grandfathered Requests
2.1 Priority Assigned: The Transmission Provider shall establish a Notification Date no later than fifteen days following acceptance by the Commission of this section, as amended in compliance with the Commission's February 21, 2001 Order in Docket No. ER00-2413-000. On the Notification Date, the Transmission Provider shall provide a draft Interconnection and Operation Agreement to each Interconnection Customer who has made a Grandfathered Request (“Grandfathered Customer”). Each Grandfathered Customer shall be given a period of twenty-one (21) days from the Notification Date or the completion of its Facilitiesy Study, whichever is later, to execute the Interconnection and Operation Agreement or to request in writing that the Agreement be filed unexecuted. Each Grandfathered Customer will be given a priority based upon the date upon which the Customer executes such Agreement or provides a written request for the filing of an unexecuted agreement pursuant to Section 1.15. A Grandfathered Customer that neither executes an Interconnection and Operation Agreement nor requests in writing requests the Transmission Provider to file an unexecuted agreement (along with the required security and assurances in accordance with Section 1.15) within such period of twenty-one (21) days will lose its place in the queue. Grandfathered Customers who have not yet executed a Phase 1 or Phase 2 System Impact Study Agreement or Facilities Study Agreement shall be given fifteen (15) days from the Notification Date to execute either the Phase 2 System Impact Study Agreement or Facilities Study Agreement, as applicable, or lose their place in the queue. Thereafter, the time periods specified in this Attachment P for non-Grandfathered Customers shall apply except that the one hundred and twenty day (120) day period specified in Section 1.15 shall not apply.
3. Transmission Service
3.1 Transmission Service: An Interconnection Request under this Attachment P to this Tariff does not constitute a request for transmission service. An Interconnection Customer may request transmission service under Parts II and III of this Tariff at the time of its Interconnection Request or thereafter. All rates, terms and conditions of Parts II and III shall apply to any such request.
3.2 Credit: The Interconnection Customer shall be entitled to a credit equal to the amount paid by the Interconnection Customer for system upgrades necessary to remove overloads, which credit will subsequently be applied by the Transmission Provider against the cost of transmission service reserved under Part II and Part III of this Tariff for delivery of electricity from the generating facility. The credit is not available for amounts paid for the minimum facilities needed to establish the direct electrical connection between the generating facility and the network or to remedy short-circuit or stability problems resulting from the connection of the generating facility to the network.
ATTACHMENT Q
Notification of Intent to Install and Operate
Generation Interconnected with AEP Transmission System
1. The undersigned Interconnection Customer submits this Notification of Intent to Install and Operate Generation pursuant to Attachment P to the AEP Open Access Transmission Tariff.
2. An Interconnection Customer requesting interconnection to the AEP Transmission System of a generating project must provide the following:
a. Location of the proposed generating plant site:
b. Size in megawatts of generating unit(s) or increase in capacity of existing generating unit(s):
c. Description of the equipment configuration and proposed connection one-line diagram:
d. Planned in-service date of the new generating unit(s) or increase in capacity of the existing generating unit(s):
e. Type of generating unit(s):
f. Name and Location of nearby AEP transmission facilities where the proposed generation is likely to be connectedDate of Application:
g. Name, address, telephone and fax numbers and e-mail address of the contact person:
h. A non-refundable deposit in the amount of $10,000.00. Checks may be made payable to American Electric Power Service Corporation.
MISCELLANEOUS
3. This Notification of Intent to Install and Operate Generation Interconnected with the AEP Transmission System shall be made to the representative of AEP as indicated below.
Mr. Bernie Pasternack
Director – Transmission Planning
American Electric Power Service Corporation
825 Tech Center Drive
Gahanna, OH 43230-8250
CONFIDENTIALITY
4. AEP will maintain on its OASIS a list of interconnection requests that identifies the size in Megawatts of the Interconnection request, location of generation, in-service date for proposed generation and date of such requests, but will not disclose the identity of the Interconnection Customer, as indicated in Attachment P of the AEP Open Access Transmission Tariff.
INTERCONNECTION CUSTOMER AUTHORIZATION
5. I, the undersigned and authorized representative of the Interconnection Customer, submit this Generation Interconnection Request for AEP’s review process, with the understanding that AEP will subsequently provide a System Impact Study Agreement, including Scope of Study and estimated cost of conducting the System Impact Study. The System Impact Study Agreement should be mailed to the following address.
_______________________
_______________________
_______________________
Authorized Signature: ____________________ Date: __________________
Name (PRINT): _________________________ Title: __________________
Company Name _________________________
ATTACHMENT R
FORM 715
TRANSMISSION PLANNING RELIABILITY CRITERIA
1. The American Electric Power System Transmission Planning Criteria and Assessment Practices (FERC Form 715, Part 4 and Appendices A – D)
2. West Texas Utilities and Central Power & Light Co. Transmission Planning Reliability Criteria (FERC Form 715, Part 4)
3. Public Service Company of Oklahoma and Southwestern Electric Power Company (FERC Form 715, Part 4) (CSW Transmission Planning and Reliability Criteria omitted as duplicative of WTU and CPL Part 4)
THE AMERICAN ELECTRIC POWER SYSTEM
TRANSMISSION PLANNING CRITERIA
AND ASSESSMENT PRACTICES
a
Transmission System Analysis and Planning
American Electric Power Service Corporation
March 2000
INDEX
Page
Introduction 1
1. Underlying Principles and the Planning Process 3
1.1 Underlying Principles 3
1.2 Planning Process 4
2. Key Modeling Assumptions 6
3. Performance Standards 9
3.1 Thermal Limits 9
3.2 Voltage Limits 11
3.3 Relay Trip Limits 11
3.4 Stability Limits 11
3.5 Short Circuit Limits 12
4. Transmission Testing Criteria 13
4.1 Steady State Testing Criteria 13
4.1.1 Single and Double Contingencies 13
4.1.2 Multiple (ECAR Type) Contingencies 14
4.2 Stability Testing Criteria 15
4.3 Power Transfer Testing Criteria 16
4.4 Probability Concepts Applied to Area Transmission Assessment 18
4.5 Other Applications of Probability Concepts 19
Appendices
A. ECAR Document No. 1
B. List of External Documents that Relate to AEP's Transmission
Planning Criteria and Assessment Practices
C. AEP Transient Stability Disturbance Testing Criteria
D. AEP Generation Connection Criteria
The American Electric Power System
Transmission Planning Criteria
and Assessment Practices
Introduction
Electric utilities, such as AEP, meet their obligation to supply electricity demanded by their customers with a high degree of reliability through the carefully planned and integrated development of electric generating sources, transmission, and distribution systems necessary to produce and deliver the electricity to the customers. The reliable supply of electricity involves two elements -- adequacy and security. "Adequacy" relates to the production and delivery of electric power and energy in the quantity and quality that the customer requires. For example, sufficient power must be provided at acceptable voltage levels and frequency to match the customers' equipment specifications. "Security" relates to the ability to produce and deliver power whenever the customer needs it. Credible contingencies, such as the sudden outage of transmission facilities, should not result in uncontrollable power interruptions over a wide area. Planning a reliable transmission system requires the application of fundamental principles and the establishment of criteria which balance adequacy and security against the cost to provide them.
The AEP transmission system was developed over many decades. In the early days of the utility industry, power plants were small and located near load centers. Consequently, transmission distances were short and the amounts of power delivered were small. As the demand for electricity increased, larger power plants were developed to exploit economies of scale, and greater amounts of power had to be transmitted over longer distances. This led to the development of higher voltage, higher capacity transmission facilities.
As utilities developed in their respective geographic areas, the establishment of interconnecting transmission facilities between adjacent systems became attractive as a means to provide mutual support during emergencies and to avoid constructing duplicate facilities. High transmission voltages enabled power systems to interconnect on a broad scale. Interconnections allow utilities to support each other during forced or scheduled generation and transmission outages, to buy and sell power for reasons of economy and to enhance reliable operation. On the other hand, each interconnected system is unavoidably affected by events on neighboring systems, requiring coordinated planning and operating practices among neighboring systems and regions. Facility outages and variations in generation dispatch within one system will affect power flow patterns in neighboring systems. Consequently, cascading outages that affect widespread areas are possible. The highly interconnected nature of electric utilities has made it necessary that system planning criteria evolve to recognize these changing interdependent conditions of interconnected operation.
This document describes the criteria that AEP uses for planning a reliable transmission system to meet its customers' needs at the lowest possible cost. The first section describes the principles underlying the planning criteria and discusses the planning process. The following three sections provide details of modeling assumptions, performance expectations, and testing criteria, respectively, for AEP's bulk transmission system and area transmission system.
AEP's bulk transmission system, which consists of an extensive network of extra high voltage (EHV) facilities operating at 765 kV, 500 kV, 345 kV, and 230 kV as well as key 138 kV facilities, delivers power from generating plants to major load centers, connects load centers together to form an integrated network, and connects the AEP System to neighboring companies. The area transmission system, which consists of high voltage (HV) facilities operating at 161 kV and 138 kV and low voltage subtransmission facilities (from 23 kV to 88 kV), moves power within the major load centers and delivers it to distribution centers and major customers. Even though AEP's bulk and area transmission systems are planned and operated on a totally integrated basis, the planning criteria of each differ because of separate and distinct functions that each of these systems are intended to serve.
1. UNDERLYING PRINCIPLES AND THE PLANNING PROCESS
1.1 Underlying Principles
Although planning is essential in any industry, it is critically important for electric utilities because of the characteristics of an electric power system: the inherent need to respond instantaneously to the electric power demand of customers (load); the heavy financial investment and long service lives of its facilities; the long lead and construction times to add facilities; and the social and economic importance of a reliable power supply. AEP has adopted fundamental planning principles as the basis for specific reliability criteria. Briefly, these principles state that a properly designed transmission system should provide a good balance or distribution of power flows by avoiding excessive geographic concentrations of generating sources or transmission paths. A transmission system should provide ample margin for contingencies to avoid uncontrolled, area-wide power interruptions and also provide flexibility to deal with the uncertainties inherent in making long range forecasts. Interconnection capabilities should be maintained commensurate with the amount of system load and the size of the system's individual generating units and generating plants. Station switching arrangements, relay protection, and system controls should be adequate to maximize the use of the transmission system and minimize interruptions; and to provide for scheduling required maintenance as well as facilitating the restoration of outaged facilities.
It is impossible to anticipate or test for all possible contingencies that could adversely affect the AEP transmission system because of the large number of individual elements that comprise the system and the fact that power flows are continually changing. Therefore, the planning criteria and related contingency tests outlined in this report do not represent an exhaustive set of system operating conditions, transfer levels, and specific contingencies; instead, they constitute an effective and practical means to stress the AEP transmission system, testing its ability to survive the entire spectrum of possible contingencies and identifying potential weaknesses and problems.
The AEP criteria described herein are compatible with: 1) the North American Electric Reliability Council (NERC) Planning Standards and NERC's Operating Policies; 2) the East Central Area Reliability (ECAR) Coordination Agreement Document No. 1, "Reliability Criteria for Evaluation and Simulated Testing of the ECAR Bulk Electric Systems" (Appendix A); and 3) other external documents. A listing of those external documents is provided in Appendix B. The application of the NERC and ECAR criteria to any particular utility system, including AEP, must be adapted to the specific characteristics of that utility. Each utility's transmission system is configured in a way that is specific to the geographic region it serves as well as the electrical facilities that are installed to meet these requirements. There are also various ways of achieving reliability objectives. Therefore, differences can exist among the specific planning criteria employed by various systems. Compatibility among different systems' criteria and guidelines are achieved, however, by adopting fundamentally sound planning principles and practices.
This report presents an overview of AEP's transmission planning criteria and assessment practices. Specific application on a case-by-case basis must employ sound engineering judgement. The system planner conducting each study should always evaluate these criteria and refine them to account for special considerations applicable to the study area.
Due to inherent uncertainties associated with forecasts of loads, new technological developments, equipment costs, and changing social, economic, and political conditions, it is prudent to develop long range plans of system expansion/modification based on a range of assumed scenarios. Sensitivity analysis is also useful in making these judgements. By their very nature, long range plans must be reviewed and modified periodically to reflect the persistent changes in a variety of factors that influence future system performance. While current planning criteria are inherently deterministic, qualitative distinctions about the likelihood of various scenarios and contingencies are recognized.
More likely events require higher levels of system performance; lower system performance standards (greater negative impacts) are acceptable for events that are less likely to happen. Deterministic reliability criteria that are sufficiently stringent to ferret out potential system problems may also result in specific design consequences which are impractical or too expensive in relation to the benefits realized. In that case, exceptions to the criteria must be made, or other less expensive control schemes employed.
1.2 Planning Process
The planning process, as carried out by AEP's Transmission System Analysis and Planning organization, provides the focus for establishing an appropriate level of system reliability. That process encompasses a continuum of activities beginning with near term assessments, or appraisals, of system performance to long term facility addition studies and longer term strategic planning. The planning process typically begins with a deterministic appraisal of transmission system performance. When such appraisals identify potential problems, detailed studies are conducted to evaluate the severity of the problem and to develop an optimal plan to remove or mitigate the deficiency.
Near term assessments, also referred to as operational planning, look ahead up to 1 year. These appraisals verify that the transmission system, as planned and built based on long term predictions and assumptions, is adequate to meet the actual requirements that emerge. Delays in transmission reinforcements, and changing power flow patterns or performance expectations, also influence the need for short term appraisals. These appraisals also provide an early warning of future system reinforcement needs. Operational planning appraisals are conducted in a manner similar to facility planning appraisals. The major difference is that problems cannot be corrected by transmission reinforcements due to insufficient lead time. Short term studies focus on deriving indices for system operators to monitor system performance and on establishing operating procedures to mitigate any transmission problems detected by the operators.
Long term facility planning appraisals analyze anticipated system conditions over a time period from 1 to 10 years into the future. Long term planning of the transmission system allows adequate time to identify emerging trends and system deficiencies and then to plan and build needed transmission reinforcements, including time for lengthy regulatory approval processes. Conceptual strategic planning studies beyond the 10 year period provide a vision of fundamental changes underlying the planning process as well as a framework for coordinating the development of specific transmission reinforcements that have differing time and spatial attributes.
Long term facility planning and near term operational planning studies are conducted for both the bulk transmission system and the area transmission system in accordance with their respective testing criteria and performance expectations. The majority of these studies are conducted internally by AEP system planners, using information generally available from neighboring electric utilities. However, as needed, joint planning studies involving one or more neighboring systems are carried out to assess and enhance interfaces between AEP and its neighbors through coordinated operating procedures or development of new interconnection facilities.
Recently, AEP has received many requests from Independent Power Producers for interconnection of new generators to the AEP transmission system. AEP has developed a specific planning process for such studies. Details of that process are provided in Appendix D.
In addition, both long term and short term appraisal studies, limited to assessing regional and inter-regional system performance, are conducted jointly with neighboring utilities as part of ECAR and interregional agreements. These joint appraisals focus on measuring the strength of the interconnected network and on assuring coordination of facility planning and operational planning efforts. Where such assessments uncover deficiencies, the problems are referred to the appropriate company or companies to develop solutions as part of their normal planning process.
This document does not directly address regional and interregional appraisal criteria except to note that AEP's criteria comply with those in ECAR Document No. 1 and NERC’s Planning Standards and Operating Policies. Also, AEP uses regional and interregional transfer capability measures, that are consistent with the NERC definitions, to assess the strength of its transmission system. AEP is an active participant in many regional and interregional study groups and has made significant contributions to the development of regional and interregional criteria, including ECAR Document No. 1, the NERC Planning Standards, and the NERC Operating Policies.
2. KEY MODELING ASSUMPTIONS
The computer models used in transmission planning studies necessarily differ widely in dimensions and details to suit the scope of each study. Load flow base case models are developed to represent system operation during highly stressed periods such as peak load conditions and heavy power transfers that simulate emergency and opportunity power transactions. A variety of other computer models are also used, depending on the specific analysis, to complement the load flow models. These include system dynamics and short circuit computer programs. System performance is assessed by simulating disturbances using these computer models to identify system strengths and weaknesses. In general, the following assumptions are used in conducting various types of transmission planning studies.
System active power (MW) loads are often represented at extreme weather, peak, off-peak, and/or light load levels depending upon the type of analysis being conducted. The load levels for studies of the HV and EHV systems are based on the forecasts of diversified peak demand (developed for transmission analysis purposes) provided by AEP's Integrated Resource Planning Division of the Corporate Planning and Budgeting Department. These forecasts include both the loads of full requirements customers and customers taking transmission service within the AEP control area. For studies of the subtransmission system, load levels are based on peak demands of individual load areas.
Facility planning studies usually simulate performance during peak load periods because this is the condition that produces the most heavily loaded transmission conditions. There are exceptions due to: 1) pumped storage hydro characteristics, and 2) the fact that the heaviest power transactions often occur at load levels 10-20% below peak. Sensitivity analyses are conducted to investigate the impact of optimistic and pessimistic load growth forecasts on the expansion/modification plans being considered. For most studies of AEP's internal system, subtransmission system loads are modeled in order to capture the effects of shunt capacitors, TCUL transformers, and the hydro-electric generators that are connected to the subtransmission system. Broader regional and interregional studies generally model loads only at the 138 kV and higher voltage levels.
For near term operational planning studies, two typical peak load levels are used. One is based on the forecasted peak with a recurrence of once in two years. The other is based on extreme weather with a recurrence of once every five years. The load level for an extreme weather forecast is generally 104-106% of the forecasted peak.
Reactive power (MVAr) loads are based on the measured power factor for each load area. It is assumed that reactive correction will be provided as load increases in the future to maintain that power factor. Where future system assessments indicate a need for additional power factor correction, appropriate reinforcements are proposed to meet AEP's design goal that each voltage level is not a reactive burden to its source system. When extreme weather forecasts are modeled, the power factor of the incremental load (above the base load) is assumed to be 80% because power factor correction is not provided for load that exceeds the forecast.
Power transfer levels modeled in base cases for analysis of the AEP System vary from one study to another depending on the particular focus of the study. The NERC Multi-Regional Modeling Working Group (MMWG) load flow base cases generally model only committed firm energy commitments. The ECAR cases, which are derivatives of the NERC cases are modified to include additional recently experienced power transfer biases. AEP's base cases, which are derived from the ECAR models, may require further updates and detail. Often high levels of transfers are simulated to reflect parallel flow conditions reflecting recent experience and in order to assure that probable system bottlenecks are identified.
Generators are normally dispatched economically to meet the load demand for system conditions being studied. Most generators will be modeled at or near full output for peak load conditions while some units will be at minimum levels for light load conditions. In addition, for operational planning studies, the generation dispatch reflects scheduled maintenance. In some cases, the generation dispatch may be adjusted to more accurately reflect other constraints or typical dispatch levels of the units. Pumped storage units are dispatched in the pumping, generating, or condensing mode, depending on system load level and other typical operating constraints such as generating unit minimum output levels. Emergency dispatch models may also be used to simulate actions taken to relieve operating problems or to simulate a response to an extreme condition. In the absence of specific information, non-utility generators are modeled in the same manner as utility generation for transmission study purposes.
Base cases model all transmission facilities in service except for known scheduled maintenance, long term construction outages, or long-term forced outages. These known outages are normally only reflected in operational planning studies. Because it is impractical and unnecessary to represent all interconnected systems in detail, the extent of the interconnected network representation is dictated by the type of planning study. Thus, an interconnection study involving the bulk transfer of power between two power systems, not only would require sufficient detail of the bulk transmission in each participating system but also would include sufficient detail and/or equivalent representation of other interconnected systems to assure proper analysis of critical elements.
Sufficient modeling of neighboring systems is essential in any study of the AEP bulk transmission system. Neighboring company information is obtained from the latest regional or interregional study group models, the ECAR base cases, the NERC MMWG load flow library or the neighboring company itself. In general, sufficient detail is retained to adequately assess all outages and changes in generation dispatch which are contemplated in the particular study. Other areas are usually reduced to a mathematical equivalent.
With the load flow base cases described above, the planner develops scenarios which are surrogates for a wide range of actual conditions. Numerous facility outages and power transfers occur daily in the interconnected network. It would be impractical to simulate all such conditions in planning studies. In order to establish a manageable set of base case scenarios, historical data and experience are employed. History may not be a perfect indicator of the future, but it provides valuable information to benchmark the base case models. For future load flow base cases, further adjustments are made to reflect forecasted load levels, expected facility changes, and projected power transfers, as well as emerging trends that will affect historical power flow patterns.
Load flow models described above are the most frequently used models for system planning studies. Transient stability and short circuit studies are also used to evaluate the system performance during and immediately following fault conditions on the transmission system. The network configurations used in the load flow models also provide a starting point for transient stability and short circuit studies. In addition, for transient stability studies, additional impedance and electromechanical detail of generators and their controls are included. Three-phase models of the power system are employed to study single-phase switching and other unbalanced operating configurations.
3. PERFORMANCE STANDARDS
Performance standards provide the basis for determining whether system response to the contingency tests is acceptable. Depending on the nature of the study, one or more of the following five types of performance standards will be applied: thermal, voltage, relay, stability, and short circuit.
In general, system response to contingencies evolves over a period of several seconds or more. Steady state conditions can be simulated using a load flow computer program. A short circuit program can provide an estimate of the large magnitude currents, due to a disturbance, that must be detected by protective relays and interrupted by switchgear. A stability program simulates the power and voltage swings that occur as a result of a disturbance, which could lead to undesirable generator/relay tripping or cascading outages. Finally, a post contingency load flow study can be used to determine the voltages and line loading conditions following the removal of faulted facilities and any other facilities that trip as a result of the initial disturbance. For the AEP System, thermal and voltage performance standards are usually the most constraining measures of reliable system performance. An experienced analyst, therefore, can usually rely primarily on pre-disturbance and post-disturbance load flow solutions. Each type of performance standard is described in the following discussion.
3.1 Thermal Limits
Thermal ratings describe transmission facility loading limits. Normal ratings are generally based upon no loss of facility life or equipment damage. Emergency ratings accept some loss of life or strength, over a defined time limit for operation at the rated loading level. The thermal rating for a transmission line is defined by the most limiting condition, be it a conductor capability, sag clearance, or terminal equipment rating. When a line is terminated with multiple circuit breakers, as in a ring bus or "breaker and a half" configuration, it is assumed that the line flow splits equally through the terminal equipment unless one breaker is open. Ratings in load flow simulations normally assume all breakers are in service.
Thermal ratings for major transmission equipment are normally the most limiting constraints. Other ancillary equipment, such as metering CTs and relays, also have thermal limits but these limitations are not generally treated as restrictions to system operation because such equipment can usually be replaced as needed at modest cost. However, these overloads are noted so that appropriate steps may be taken. In addition, during extreme conditions testing, it is essential to determine whether relay or switchgear failure or misoperation will result in cascading outages and power interruptions.
Normal ratings are applied in all planning studies for base and transfer conditions without outages. In long-term facility planning studies, the thermal limits are dependent on the system and time frame being evaluated. For testing the bulk transmission system (exclusive of power transfer capability studies described in subsection 4.3), facility normal ratings should not be exceeded for single contingencies. In contrast, for area transmission studies, the emergency ratings of 138 kV facilities should not be exceeded for single contingencies. This important distinction between bulk transmission (EHV) facilities and area transmission (138 kV) facilities stems from differences in function and the greater variability and uncertainty associated with bulk transmission loading patterns. Therefore, to compensate for this effect, a greater margin is provided for EHV facilities by using the more conservative normal rating. For testing involving ECAR-type multiple contingencies, potential overloads should not require corrective action unless the post contingency conditions would lead to widespread, uncontrolled outages.
For operational planning, where near term uncertainties are fewer, emergency ratings are used to assess performance following single contingencies but before any applicable operating procedures are implemented. Following an outage, system operators will implement available operating procedures to reduce all facility loadings to within normal ratings to avoid exceeding emergency ratings should the next contingency occur. The application of these facility loading limits is summarized in Table 1. Where the ability to operate at loading levels up to emergency ratings is critical to acceptable system performance, the emergency ratings are verified. This is particularly important in the case of transmission lines which may be limited by sag clearances.
Most thermal ratings are defined in amperes. However, transmission planning studies use ratings expressed in MVA, based on the ampere rating at nominal voltage. When voltages during testing deviate considerably from nominal, the MVA rating is adjusted for the voltage deviation from nominal.
|Table 1 |
| |
|AEP Transmission Planning Criteria |
|(Steady State System Performance) |
| | |Minimum |
| | |Bus Voltage |
| |Maximum Facility | |
|Transmission System Condition |Loading (Rating) | |
| | |EHV |138 kV |
|All facilities in service | Normal |95% |95% |
|One facility out of service | Emergency (1) |90% |92% |
| |Normal (2) | | |
| |Emergency (3) | | |
|Two facilities out of service | Emergency |90% |92% |
|(1) Operational planning criteria before operating procedure implemented. |
|(2) Facility planning criteria (EHV facilities). |
|(3) Facility planning criteria (138 kV facilities). |
3.2 Voltage Limits
Voltages at transmission stations should be above the values listed in Table 1 to reduce the risk of system collapse and/or equipment problems. In addition, voltages at generating stations below minimum acceptable levels established for each station must be avoided to prevent tripping of the generating units. High voltage limits are equipment dependent, but are typically 105% of nominal.
3.3 Relay Trip Limits
Relay trip settings, selected primarily for fault conditions, could be reached in some cases during contingency loading conditions or transient power swings. These relay trip settings are evaluated in operational planning studies to determine whether adjustments are needed. If it is not practical to revise the setting, subsequent planning studies must recognize that the line could trip due to the resultant contingency loading condition.
3.4 Stability Limits
Stability limits can be of several types, depending on system characteristics.
The steady-state stability limit (PMAX in Figure 3.1) is the point at which no more power can flow through a system without precipitating a voltage collapse. This limit is often related to heavily loaded systems where even small perturbations, such as the normal adjustment of generator output to match load, could cause system collapse. Steady state stability limits are typically evaluated using power vs. voltage (PV) curves or power vs. angle curves, for individual lines or transmission interfaces. In planning studies, a loadability limit is defined, which includes a safety margin of 5-10% below the theoretical maximum power flow.
Transient stability refers to a power system's ability to remain in synchronism following a disturbance, such as a short circuit. Ideally, facilities should be planned and operated so that all generating units remain stable through the transient period even if operating at full output prior to the disturbance. Also, transient voltage dips at generating stations below established minimum acceptable levels should be avoided to prevent tripping of the auxiliary loads, which in turn, could trip generating units.
Oscillatory stability refers to a power system's ability to damp out electromechanical oscillations, in the 0.1-3.0 Hz range, that inherently exist on the system. Oscillatory instability is manifested in terms of sustained or growing oscillations in various electrical quantities observable at power plants and on the transmission system, following a mild or severe disturbance, or a routine network operation such as load ramping. These oscillations must be suppressed within seconds to prevent potential equipment tripping and damage. The oscillatory instability limit is defined as the power level beyond which one or more generators (or groups of generators) continue to exhibit one or more sustained modes of oscillation beyond a reasonable time limit. Generally, this limit is not dependent
on the size of the disturbance or the period of the mode. Any sustained or growing oscillation which persists beyond a reasonable time limit indicates that the stability limit has been exceeded and represents unacceptable performance.
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3.5 Short Circuit Limits
Short circuit limits are also an important aspect of system performance, since the extremely high, short duration currents that accompany system faults will impose considerable stresses on network elements. Circuit breakers must be capable of interrupting the anticipated fault currents in the shortest possible time. Failure to interrupt these currents may lead to catastrophic equipment damage and danger to human life. Short circuit levels increase as network reinforcements are implemented or new generating units are added to the system. Therefore, short circuit levels must be reviewed periodically and inadequate equipment must be replaced or upgraded, or a mitigation procedure is employed.
4. TRANSMISSION TESTING CRITERIA
4.1 Steady State Testing Criteria
The planning process for AEP's transmission network embraces two major sets of testing criteria to ensure reliability. The first set, which applies to both bulk transmission and area transmission assessment and planning, includes all critical single and double contingencies. The second set, which is applicable only to the bulk transmission system, includes more severe multiple contingencies (such as those described in ECAR Document No. 1) and is primarily intended to assess the potential for system cascading.
For bulk transmission planning, the testing criteria are deterministic in nature; these outages serve as surrogates for a broad range of actual operating conditions that the power system will have to withstand in a reliable fashion. The planning for area transmission supplements the deterministic criteria with a probabilistic approach to performance assessment. Additional applications of probability concepts to the transmission planning process are described at the end of this section.
4.1.1 Single and Double Contingencies
The testing criteria for area transmission are usually limited to single-contingencies for the LV transmission system (23 kV to 88 kV) and single or double-contingencies for the HV transmission system (138 kV and 161 kV). This contrasts with the criteria for the EHV transmission system where more severe multiple contingencies are also considered. This difference is appropriate because of the limited geographical scope of area transmission systems as compared to the broad geographical scope of bulk transmission systems, with the attendant increase in system variables and potential for blackouts affecting a large geographical area should a cascading outage of the bulk transmission system occur. In essence the testing criteria represent a continuum where more stringent tests are applied as the geographic extent of the area and the number of customers and amount of load increase. In principle, this approach strikes a rational balance among risk, reliability and the cost of system reinforcement.
Contingencies include the forced or scheduled outage of generating units, transmission circuits, transformers, or other equipment. In general, a single contingency is defined as the outage of any one of these facilities. Due to the interconnected nature of power systems, testing includes outages of facilities in neighboring systems. A single facility is defined by the arrangement of automatic protective devices. Generally, double circuit tower outages, breaker failures, station outages, common right-of-way outages, and other common mode failures have substantially lower probabilities of occurrence than the outage of a single transmission facility and are, therefore, not considered single contingencies.
Double contingencies, being a more severe test of system performance, are used as a surrogate for the significant uncertainties that are inherent in the planning process. Double contingency tests are frequently applied in facility planning studies of the bulk transmission and HV area transmission systems of AEP. Typically, these tests determine the need for transmission system enhancements.
For facility planning purposes, contingencies result from scheduled maintenance and/or forced outages. Double outages are generally viewed as separate events which overlap in time. Each contingency is tested with the system load level, generation dispatch, and generating unit outages which would be most severe, but still credible, for that particular contingency.
Single contingencies are tested with firm import and export transactions, third party transfers, and the expected level of AEP opportunity transfers, i.e., the desired first contingency total transfer capability (FCTTC) level. Double contingencies are tested with the maximum expected level of AEP firm transfers and third party transfers which affect the AEP System. The import scenarios assume planned imports plus an additional level of imports necessary to assure that the AEP control area loss of load expectation will be no greater than one day in ten years. Furthermore, since the availability of off system resources is uncertain, the transmission system must be capable of importing these resources across a limited number of interfaces when these resources are not available from one or more directions. Sensitivity studies are also normally conducted for a range of opportunity transfers and generation dispatches as well as extreme weather conditions.
Contingency tests of the transmission system, related to connection of new generation, take on an additional dimension. AEP has used an extreme test of loss of a double-circuit tower line and an additional transmission element. If the transmission system cannot survive this test, at full generation levels, then options are provided to the generation project developer to either pay the cost to reinforce the system or to develop automatic control schemes to reduce or shutdown the generation, to prevent overload of transmission facilities.
It is recognized that the loss of a double-circuit tower line and an additional transmission element is beyond a double contingency, but it is not a triple contingency. Since a double-circuit tower line can experience common mode failures, loss of both circuits has a greater likelihood than a typical double contingency. This extreme test for generation additions is applied whenever firm generation resources are desired.
Operational planning studies consider up to two key outages in effect prior to the next (third) contingency. It is assumed that all operator adjustments required for the prior outages have been implemented. Uncertainties such as generation availability and dispatch, load forecast error, and load diversity are also considered. The number of prior outages depends on the strength of the transmission system and the number of variables to be considered in developing effective operating guidelines. Clearly, as the number of concurrent contingencies increases, it will become increasingly difficult to meet the required performance limits (see Section 3), even with special operating procedures.
The number of outages actually occurring on the system can exceed the number assumed for study purposes. Operational planning engineers evaluate those conditions, as needed.
4.1.2 Severe (ECAR Type) Contingencies
The more severe Reliability Assessment Criteria required in ECAR Document 1 are primarily intended to assess the risks for uncontrolled area-wide cascading outages under adverse but credible conditions. AEP, as a member of ECAR, plans and operates its bulk transmission system to meet the criteria of ECAR Document No. 1. However, new facilities would not be committed on the basis of local overloads or voltage depressions following the more severe ECAR type multiple contingencies unless those resultant conditions were expected to lead to widespread, uncontrolled outages.
In operational planning studies, the purpose of studying multiple contingencies and/or high levels of power transfers is to evaluate the strength of the system. Where conditions are identified that could result in significant equipment damage, uncontrolled area-wide power interruptions, or danger to human life, operating procedures will be developed, if possible, to mitigate the adverse effects. It is accepted that the defined performance limits could be exceeded on a localized basis during the more severe ECAR type multiple contingencies, and that there could be resultant minor equipment damage, increased loss of equipment life, or limited loss of customer load. Normally, operating procedures to mitigate uncontrolled area-wide power interruptions are only used on an interim basis until facility additions can be put in place to restore acceptable reliability levels.
In carrying out operational or facility planning studies, it is recognized that there are many protective and special controls on the system that must operate properly when an event occurs. These controls include but are not limited to: protective relays, breaker failure schemes, quick reactor or capacitor switching, rapid generating unit runback, automatic motor operated disconnects, and emergency generator tripping. The misoperation of any of these controls may result in equipment damage, but should not result in widespread power interruptions or danger to human life.
If the facility planning process has been thorough, the forecasts of system requirements have been reasonably accurate, and facilities have been placed in service as planned, then the need to develop special operating procedures during operational planning studies should be limited to those contingencies which exceed the planning criteria. However, forecast inaccuracies and delays in facility additions, could result in an existing system which does not meet planning criteria. Therefore, special operating procedures, including the shedding of firm load, may be required until planned facilities are placed in service, to survive contingencies which are covered by the planning criteria.
4.2 Stability Testing Criteria
Stability testing covers the entire range of power system dynamics from "first swing" transient stability to the longer term oscillatory and steady-state stability. This testing is an essential complement to the steady state analysis embodied in the load flow testing described above.
Power plant transient stability is an important consideration since loss of synchronism of a generating unit or an entire generating plant in addition to compounding the disturbance by the loss of generators can lead to equipment damage. When simulating system contingencies affecting power plant stability, various types of fault and network conditions are analyzed using the transient stability performance testing criteria outlined in Appendix C.
Steady-state and oscillatory stability performance problems may be initiated by a wide variety of contingencies or operating conditions on the transmission network. Therefore, a wide variety of network disturbances are considered when testing for steady-state and oscillatory stability problems. Referring to Appendix C, AEP generally carries out simulations corresponding to the A through E set of criteria for facility planning studies. For operational planning studies, the F and G criteria, in addition to the A-E set, is applied, especially when a long-term facility outage is anticipated. It should be noted that additional testing, more severe than that shown in Appendix C, may be done to evaluate the strength of the transmission system and/or to assess potential for cascading outages. Examples of such testing include: 1) a common-failure mode of disturbance that can result in an outage of multiple facilities at a location, with no prior outage; and 2) a permanent fault with a breaker failure, with the prior outage of one or two facilities.
Acceptable performance limits for all types of stability performance are discussed in Section 3.
4.3 Power Transfer Testing Criteria
The power transfer capability between two interconnected systems (or sub-systems) with all facilities in service or with one or two critical components out of service, indicates the overall strength of the network. Many definitions of power transfer capability are possible, but uniformity is highly desirable for purposes of comparison. Furthermore, transfer capability, however defined, is only accurate for the specific set of system conditions under which it was derived. Therefore, the user of this information needs to be aware of the conditions under which the transfer capability was determined and those factors which could significantly influence the capability.
AEP has adopted the definitions of transfer capability, published by NERC in "Transmission Transfer Capability", dated May 1995. The most frequently used transfer capability definition is for First Contingency Incremental Transfer Capability (FCITC) and is quoted below from the referenced NERC publication:
First Contingency Incremental Transfer Capability
"FCITC is the amount of power, incremental above normal base power transfers, that can be transferred over the transmission network in a reliable manner, based on the following conditions:
1. For the existing or planned system configuration, and with normal (pre-contingency) operating procedures in effect, all facility loadings are within normal ratings and all voltages are within normal limits.
2. The electric systems are capable of absorbing the dynamic power swings, and remaining stable, following a disturbance that results in the loss of any single electric system element, such as a transmission line, transformer, or generating unit, and
3. After the dynamic power swings subside following a disturbance that results in the loss of any single electric system element as described in 2 above, and after the operation of any automatic operating systems, but before any post-contingency operator-initiated system adjustments are implemented, all transmission facility loadings are within emergency ratings and all voltages are within emergency limits."
First Contingency Total Transfer Capability (FCTTC) is similar to FCITC except that the base power transfers (between the sending and receiving areas) are added to the incremental transfers to give total transfer capability. ECAR has adopted standards for interpreting and applying the NERC transfer capability definitions, and AEP uses these guidelines in its internal studies as well.
While the first contingency transfer capabilities are the most frequently used measure of system strength, transfer capabilities also can be calculated for "no contingency" and "second contingency" conditions.
In April 1996 the Federal Energy Regulatory Commission issued two rules -- Orders No. 888 and 889. Two aspects of these rules are "open access" to the transmission systems of integrated utilities and the posting of available transfer capacity. The ability of a transmission system to permit power transfers is defined by several terms, namely:
Firm Available Transfer Capacity (ATC)
Firm Total Transfer Capacity (TTC)
Non-firm ATC
Non-firm TTC
Transmission Reliability Margin (TRM)
Capacity Benefit Margin (CBM)
The ATC/TTC values provide an indication of the ability of the transmission system to support transfers. Firm ATC is the level of additional transfer capability remaining in the physical network for further commercial activity over and above existing commitments, and purchases of firm ATC will have service priority equal to AEP’s native/network load. The ATC/TTC values are calculated for transactions in both directions between AEP and directly connected control areas and for selected commercially viable through paths across the AEP System. ATC values are the lesser of network capability or contract path capacity (i.e., the total capability of interconnections to a neighboring control area). Firm TTC is determined by adding firm schedules and/or reservations to the firm ATC values.
Non-firm ATC's and TTC's are calculated in a manner similar to that used to calculate the firm values, except that both firm and non-firm transactions are included in the calculations. For TTC calculations, AEP has adopted the policy that there should be a single value representative of both firm and non-firm TTC. Therefore, TTC is set equal to the higher of firm TTC or non-firm TTC.
TRM is the amount of transmission margin required to ensure that the transmission network is secure under a range of uncertainties in operating conditions. These uncertainties include generation unavailability, load forecast error, load diversity, unknown outages in neighboring systems, and variations in generation dispatch. The TRM is applied directly to facility ratings for calculations of firm ATC/TTC. For situations where the transmission system is thermally limited, the seasonal/emergency capability of the critical facilities is reduced. The amount of the reduction increases as the analysis horizon increases. In instances where the transmission system is voltage or stability limited, system performance surrogates, such as line loadability or area voltages, are used as capability measures. TRM is applied only to firm ATC calculations.
CBM is the amount of transfer capability required by Load Serving Entities to ensure access to generation from interconnected systems to meet generation reliability requirements. The total AEP CBM value is based upon generation reserve requirements and the ability of the AEP transmission system to import emergency resources to achieve a loss of load expectation of no more often than one day in ten years. This transmission capacity is in addition to any planned imports. CBM is subtracted as a fixed MW amount from the firm AEP TTC import capability. The CBM is allocated among AEP’s interfaces and the amount allocated to individual interfaces is based upon expected available generation resources, transfer capability, and interconnection capability of each interface.
AEP methodologies to calculate these values are consistent with the “NERC Available Transfer Capability” and the “ECAR TTC/ATC Calculation/Coordination Document.”
4.4 Probability Concepts Applied to Area Transmission Assessment
The evaluation of the need for area transmission reinforcements is based on probabilistic techniques, applying the principal that:
Risk x Amount of load affected = Constant
The constant, which represents a threshold value for determining reinforcement need, is selected based on engineering judgement and then applied uniformly for all area transmission analyses. In selecting the constant, some risk of undesirable performance is accepted, but this risk is held to a manageable level. Clearly, this principle also implies that for larger load areas less risk is taken and vice versa.
The goal of the probabilistic approach is to quantify the risk (via a project index) of disrupting service to an area due to contingencies. Project indices above the threshold are then used to justify the need for improvement programs. There are three steps in the development of a project index, namely:
a) calculate risk indices
b) calculate contingency indices
c) calculate a project index
The risk indices are calculated for each contingency. They are defined by three probabilities:
i) the probability of a piece of equipment being unavailable due to an outage and its associated restoration time
ii) the probability of an area load at the time of an outage being at or above the critical level that will cause power supply network problems
iii) the probability that an overloaded facility will fail and/or a voltage depression will cause a disruption of service
For each contingency a risk index is calculated by the product of these three probabilities.
The contingency indices are calculated as the products of the individual risk indices and the load affected by each risk index. Where multiple contingencies cause performance violations that require system reinforcement or modification, the project index is the sum of the contingency indices.
4.5 Other Applications of Probability Concepts
At this time, probability concepts have made greater penetration into the area transmission planning process than the bulk transmission planning process. This is a reflection of the fact that more of the factors affecting area transmission planning, such as area loads, can be defined probabilistically. Bulk transmission planning, on the other hand, is impacted by a much wider variety and number of interconnected system variables. Many of those variables are difficult to predict in terms of probability distributions.
The following brief descriptions identify some of the ways in which probability concepts are presently being utilized by AEP.
( The interpretation of the ECAR testing criteria and selection of specific tests implicitly considers probabilities. For example, AEP uses only the more probable single phase fault at 765 kV stations when testing transient stability performance for multiple contingencies. This decision was based on a review of the probability of various types of faults at 765 kV and lower voltages.
( Probability concepts have been used to evaluate operational flexibility. As an example, the "window" for performing scheduled maintenance on critical facilities that serve an area can be determined by examining the area's load duration curve in relation to the expected outage duration of the key facilities.
( Probability distributions of historical parameters, such as power transfer levels and critical facility loadings have been employed to calibrate the assumed base case conditions and thereby improve the realism and quality of study results.
( As part of the process for selecting reinforcement plans, probability concepts are being used. For example, when new station facilities are being added, different station configurations can be studied, using various outage statistics to evaluate the tradeoff between reliability and cost for alternative configurations.
( Probability techniques are used to determine the need for transformer spares.
This is by no means an exhaustive list of probability applications. While universal probability indices, to measure transmission system performance, are not available, there are many aspects of the planning process where the fundamental deterministic approach is being enhanced by probability techniques.
Appendix A
East Central Area Reliability Coordination Agreement
Document No. 1
RELIABILITY CRITERIA FOR EVALUATION AND SIMULATED TESTING OF THE BULK ELECTRIC SYSTEMS
___________________________________________________________
TABLE OF CONTENTS
SYSTEM PERFORMANCE
RELIABILITY ASSESSMENTS
SYSTEM DATA MODELING
___________________________________________________________
This document contains the standards that Transmission Providers are expected to adhere to in their simulated testing and system performance evaluations in order to ensure reliable transmission performance in the ECAR region. These standards include:
System performance standards.
Reliability assessment standards.
System data modeling standards.
The standards and requirements in this document should guide individual ECAR Transmission Providers in establishing their own specific Bulk Electric System planning criteria. In doing so, the individual ECAR Transmission Providers should be able to meet, at a minimum, the Transmission System Performance and Reliability Assessment standards set forth herein.
In implementing these standards, ECAR members recognize:
The need to plan Bulk Electric Systems that will withstand adverse credible disturbances without experiencing uncontrolled interruptions.
The importance of providing a high degree of reliability for local power supply but the impossibility of providing 100 percent reliability to every customer or every local area.
The importance of considering local conditions and requirements in establishing transmission reliability criteria for the local area power supply and the need, therefore, to view reliability in local areas primarily as the responsibility of the individual ECAR members. However, local area disturbances must not jeopardize the overall integrity of the Bulk Electric Systems within ECAR.
The importance of mitigating the frequency, duration and extent of major Bulk Electric System outages.
The importance of mitigating the effect of conditions that might result from events such as national emergencies, strikes, or major outages on other regional networks.
In addition to the above, the ECAR members recognize the impossibility of anticipating, and testing for, all possible contingencies that could occur on either the present or the future Bulk Electric Systems within ECAR. They believe, therefore, that the transmission reliability criteria should serve primarily as a means to measure the strength of the systems to withstand the entire spectrum of contingencies, that may or may not be readily visualized, rather than comprise a detailed listing of probable disturbances. Ultimately, the strength of the system as planned and operated must be sufficient to assure that any load loss has not been the result of or does not result in uncontrolled power interruptions. In view of this, the selection of reliability criteria is based not on whether the specific contingencies for which the system is being tested are themselves highly probable but rather on whether they constitute an effective and practical means to stress the system and thus to test its ability to avoid uncontrolled power interruptions.
The ECAR members believe the most effective safeguard against a possible occurrence of uncontrolled power interruptions is strict adherence to basic principles of Bulk Electric Systems planning, with recognition of the entire range of anticipated operating requirements.
SYSTEM PERFORMANCE
Introduction
Individual member transmission systems provide the means to serve the load with generation resources of each area. The interconnection of Bulk Electric Systems within ECAR has allowed each system to reduce its installed reserve capacity, take advantage of short term regional transfers and increase transmission reliability. The Bulk Electric Systems should be capable of performing this function under a wide variety of system conditions (e.g., forced and maintenance outages, continuously varying loads) while continuing to operate reliably within equipment and electric system thermal, voltage, and stability limits.
Bulk Electric Systems must be planned to withstand the more probable forced and maintenance outage contingencies at projected demand and firm electricity transfer levels. Transmission Providers within ECAR may apply more stringent system performance criteria than those described herein in order to address the particular needs and concerns of the Transmission Provider.
Standards
Individual systems shall be planned such that with all transmission facilities in service and with normal (pre-contingency) operating procedures in effect, the network can deliver generator unit output to meet projected demands and provide contracted firm transmission services.
Individual systems shall be planned such that the network can be operated to supply projected demands and contracted firm transmission services with any single outage of a transmission line, transformer, special control device or generator due either to a forced outage or the failure of a primary protective device or special protective scheme.
The transmission systems shall also be capable of accommodating bulk facility maintenance outages scheduled prior to such contingencies.
Individual systems shall be planned such that the network can be operated to supply projected demands and contracted firm transmission services with contingencies such as the loss of a bus section, breaker failure, double circuit tower outage or the delayed clearing of a single line to ground fault of a generator, bus section, or transmission element. Such contingencies can result in the outage of more than one element or facility. The controlled interruption of demand, the planned removal of generators, or the curtailment of contracted firm power transfers is permitted.
The transmission systems shall also be capable of accommodating facility maintenance outages, scheduled prior to such contingencies.
Individual systems shall be planned such that Cascading shall not result from the condition of a single outage of a transmission line, transformer, special control device or generator due either to a forced outage or the failure of a primary protective device or special protective scheme, followed by a second single outage. Before or after the second contingency, the controlled interruption of demand, the planned removal of generators, manual intervention or the curtailment of contracted firm power is permitted.
Requirements
Transmission Providers shall ensure that transmission system performance with respect to Standard 1 is as summarized below:
Line and equipment loadings shall be within normal ratings.
Voltage levels shall be maintained within normal limits.
Stability of the network shall be maintained.
No unplanned loss of load, generation or contracted firm power transfers shall occur.
Transmission Providers shall ensure that transmission system performance with respect to Standard 2 is as summarized below:
Line and equipment loadings shall be within applicable ratings.
Voltage levels shall be maintained within applicable limits.
Stability of the network shall be maintained.
Planned or controlled interruption of generators or electric supply to radial customers or some local network customers, connected to or supplied by the faulted component or by the affected area, is permitted as long as it does not impact the overall security of the interconnected transmission systems. No unplanned loss of load, generation or contracted firm power transfers shall occur.
Transmission Providers shall ensure that transmission system performance with respect to Standard 3 is as summarized below:
Line and equipment loadings shall be within applicable ratings after all manual and automatic intervention has been completed. Intervention may include opening of transmission lines and transformers.
Voltage levels shall be maintained within applicable limits after all manual and automatic intervention has been completed. Intervention may include opening of transmission lines and transformers.
Stability of the network shall be maintained.
Planned outages of load or generation are permitted, and contracted firm power transfers may be curtailed.
Cascading shall not occur.
Transmission Providers shall ensure that transmission system performance with respect to Standard 4 is as summarized below:
Stability of the network shall be maintained.
Planned outages of load or generation are permitted, and contracted firm power transfers may be curtailed in the analysis.
Line and equipment loadings shall be within applicable ratings after all manual and automatic intervention has been completed. Intervention may include opening of transmission lines and transformers.
Voltage levels shall be maintained within applicable limits after all manual and automatic intervention has been completed. Intervention may include opening of transmission lines and transformers.
Cascading shall not occur.
Guides
A balanced relationship among power system elements, in terms of size of load, size of generating units and plants, strength of interconnections, and the amount of power being carried on any single transmission channel should be maintained.
This implies:
a. Avoiding excessive dependence on generating capacity in one unit, at one location, or in one area,
b. Avoiding excessive concentrations of power being carried on any single transformer, transmission circuit, tower line, or right-of-way, as well as through any one transmission station, and
Provision of interconnection capability that is commensurate with the size of the system load and with the size of generating units and plants.
Primary switching arrangements and secondary control facilities should be utilized that permit effective maintenance of equipment without excessive risk of uncontrolled, area-wide power interruptions on the interconnected network of ECAR systems.
Switching arrangements, associated relay schemes, and controls should be utilized that permit effective use of transmission capability without excessive risk of uncontrolled, area-wide power interruptions on the interconnected network of ECAR systems.
Switching and control arrangements should be utilized that provide for restoration of any part of the interconnected network within acceptable time constraints.
The planning, development, and maintenance of transmission facilities should be coordinated with neighboring systems.
In order to maintain appropriate bulk transmission bus voltages, to alleviate bulk transmission facility thermal loadings and to maintain voltage stability, adequate reactive sources, with a balance of static and dynamic characteristics, should be planned and distributed throughout the Systems.
With respect to Requirement 3 and 4, if manual intervention is used, the Transmission Provider should demonstrate that such intervention can be implemented in a timely manner relative to the dynamic response of the system. Such intervention should be restricted to those actions that can be accomplished within thirty minutes. Manual intervention is sometimes used in seasonal assessments but should normally not be used in long term assessments.
Appendix B
External Documents that Relate to
AEP's Transmission Planning Criteria
and Assessment Practices
1. ECAR Coordination Agreement Document No. 1, "Reliability Criteria for Evaluation and Simulated Testing of the Bulk Electric Systems" (see Appendix A)
2. ECAR Guide, "Simulated Stability Testing of the ECAR Bulk Power Supply Systems"
3. NERC "Planning Standards"
4. NERC "Transfer Capability - A Reference Document"
5. ECAR's Interpretation of NERC's "Transfer Capability - A Reference Document"
6. NERC Operating Policies
Appendix C
AEP TRANSIENT STABILITY DISTURBANCE TESTING CRITERIA
|PREFAULT CONDITION |765 KV PLANTS |345 KV PLANTS |138 KV PLANTS |
|All Transmission Facilities in Service |1A Permanent single line-to-ground (SLG) fault with 1 breaker failure. |
| |Fault cleared by backup breakers. |
| |2A Permanent SLG fault with 1 breaker failure. Fault cleared by |
|1B Permanent SLG fault cleared by primary breakers. 3 fault developed following |backup breakers. |
|HSR. Fault cleared by primary breakers. | |
| | |
|1C 3 line opening without fault. | |
| |3A Permanent SLG fault with 3 |
|2B Permanent 3 fault with unsuccessful HSR, if applicable. Fault cleared by backup breakers. |breaker failure. Fault |
| |cleared by backup breakers. |
|2C 3 line opening without fault. | |
| |
|3B Permanent 3 fault with unsuccessful HSR, if applicable. Fault cleared by backup breakers. |
| |
|3C 3 line opening without fault. |
|One Transmission Facility Out of Service |1D Permanent SLG fault with unsuccessful HSR, if applicable. Fault cleared |
| |by primary breakers. |
| |2D Permanent 3 fault with unsuccessful HSR, if applicable. Fault |
|1E 3 line opening without fault. |cleared by primary breakers. |
| |3D Permanent 3 fault with |
|2E 3 line opening without fault. |unsuccessful HSR, if |
| |applicable. Fault cleared by |
| |primary breakers. |
| |
|3E 3 line opening without fault. |
|Two Transmission Facilities Out of Service |1F Temporary SLG fault with successful HSR, if applicable. |
| |2F Temporary 3 fault with successful HSR, if applicable. |
|1G 3 line opening without fault. | |
| |3F Temporary 3 fault with |
|2G 3 line opening without fault. |successful HSR, if applicable.|
| |
|3G 3 line opening without fault. |
Appendix D
Generation Connection Studies
Process and Criteria for Evaluating the Impacts on the AEP Transmission System
The underlying premise of American Electric Power's (AEP's) process and criteria to evaluate the integration of a new or expanded generating plant facility is based on the premise that the generation facility owner should be responsible to mitigate any negative impacts on service reliability to existing transmission customers through the reinforcement of the network.
In the evaluation of generating plant connections to the AEP transmission system, the planning criteria must be adhered to not only for the initial year when the plant is scheduled to be placed in service but for a period of at least 5 to 10 years thereafter. In addition, the evaluation must also recognize that the EHV transmission system was designed to transmit electric power from remotely located large base-loaded power plants to local area loads. The 138 kV and the lower voltage local transmission systems were designed to distribute this power from the point of connection with the EHV transmission system to the point of consumption (i.e., directly connected customer facilities, distribution system, etc.). While the EHV transmission system in some areas may have capacity to accommodate moderate levels of new generation without significant system impacts, the local transmission, with normally smaller capacities, may not have margin available to easily integrate the new generation. New generating capacity is typically an order of magnitude greater than the connected loads (e.g., 300 MW Plant vs. 10-30 MW of connected load at a single node). In addition, circuit breakers may become inadequate from a fault interrupting perspective, as the new generating facilities will add to the fault current.
The 138 kV and lower voltage transmission systems are designed to provide margins for changing conditions. The study process for determining and implementing future facility modifications or additions takes into consideration expected load growth over a 5 to 10 year period. These analyses are conducted for normal peak load and contingency conditions to ensure continuous and reliable power delivery to the local transmission system customers.
To provide a timely response to generating facility owners, the impacts of the new generation capacity additions are studied for peak load system conditions for the initial year of connection only. Therefore, a transmission margin must be maintained to ensure reliable delivery of electric power to the continuously changing customer demands. Based on a five to ten year planning horizon and a moderate load growth rate of up to 2.5% per year, a minimum transmission margin of 13% is required. This value is applied by making transmission facility rating adjustments, i.e., thermal loading during normal and contingency conditions shall remain within 87% of line or transformer emergency capabilities during the first year of generating plant operation.
As part of the process to evaluate new capacity addition requests for connection to the transmission system, the cost responsibility of the generating plant integration must be assessed by applying AEP’s planning criteria over a reasonable planning horizon. The application of AEP’s criteria in examining generating plant connection is consistent with the existing AEP practices and criteria that are used in defining potential constraints and implementing future system modifications or additions. The intent of the process in applying AEP’s criteria in the evaluation of new generating capacity connection to the system is to maintain a level of service reliability, with the new generating capacity in service, comparable to the level that existed prior to the new generating capacity connection. Therefore, the criteria detailed below to apply AEP’s planning criteria in determining cost responsibility for system enhancements associated with the connection of new generating capacity is designed to maintain the prevailing level of service reliability and quality to existing customers.
Transmission Line Loading:
If as a result of the added generation, the loading on an EHV line would exceed its normal capability during normal or single contingency conditions, the generating plant owner shall be responsible for all system modifications required to restore the line loading to within the normal capability. Likewise, if as a result of additional generation, the loading on an EHV facility would exceed its emergency rating during double contingencies, the generating plant owner shall be responsible for the necessary system modifications to restore the EHV facility loading to within emergency capability.
If as a result of the added generation, a 138 kV transmission line loading exceeds 87% of emergency rating of the line during either normal or contingency conditions, the generating plant owner shall be responsible for all system modifications to restore the line loadings to within 87% of emergency rating or to the line loading level which would occur without the generation, whichever is greater. In some cases, limiting terminal equipment must be replaced in order to increase the capability of the line. In other cases, system improvements may be required.
If as a result of the added generation, 138 kV transmission line loadings exceed the normal rating of the conductor during normal or contingency conditions and the line has not been recently assessed for safe conductor clearance, the generating plant owner shall pay AEP to conduct a survey to check for appropriate sag clearance. If the sag checks indicate any sag violations that limit the line to less than the conductor emergency capability, the generating plant owner shall pay for the removal of those limitations.
If as a result of the added generation, transmission lines operated below 138 kV are loaded above 87% of their respective conductor capability during either normal or contingency conditions, the generating plant owner shall be required to pay for the system improvements, including the replacement of limiting station facilities, that will lower the line loading to below 87% of the line capability or to the line loading level which would occur without the generation, whichever is greater.
Transformer Loading:
If as a result of the added generation, the loading on an EHV/EHV, e.g., 765/345 kV, 500/345 kV transformer would exceed its normal capability during either normal or single contingency conditions, the generating plant owner shall be responsible for all system modifications required to restore the transformer loading to within the normal capability or to the transformer loading level which would occur without the generation, whichever is greater.
If as a result of the added generation, the loadings on any EHV/138 kV or any lower voltage transformer exceeds 87% of its emergency rating during either normal or contingency conditions, the generating plant owner shall be responsible for system modifications needed to reduce the transformer loadings to below 87% of the transformer emergency rating, or to the loading level which would occur without the generation, whichever is greater.
Short Circuit Duty:
If the short circuit duty of any existing circuit breaker would exceed its rating due to the installation of the new generating capacity addition, the generating plant owner shall be responsible for the cost to replace the affected equipment. In addition, short circuit margins exist at many stations on the AEP System to accommodate future system enhancements (such as addition of a transformer, lines, etc.) which may be required within the 5 to 10 year planning horizon to accommodate load growth. If the installation of the new generating facility depletes these margins, the generating plant owner shall be responsible for the cost on a pro rated basis (percent of margin depleted by the installation of the new generating capacity addition) to restore these margins. The margins are to be calculated based on the difference between the existing short circuit duty and the projected short circuit duty with the next planned facility in service.
Additional system improvements may also be required to transmit the output of the new generating capacity across the transmission system. Such transmission service would be provided under AEP’s OATT.
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
18 CFR Part 141.300
FERC FORM NO. 715
Annual Transmission Planning and Evaluation Report
For the Year Ending December 31, 1999
Part 4: Transmission Planning Reliability Criteria
CPL and WTU are both members of the Electric Reliability Council of Texas (ERCOT), and as a condition of membership have agreed to conform with all approved and applicable ERCOT and the North American Electric Reliability Council (NERC) Principles, Criteria, Standards, and Guides. The ERCOT Reliability Criteria and Guides are supplied to the Office of Energy Emergency Operations, Department of Energy under EIA-411, and are available for download from Internet Web Page: . The ERCOT Reliability Criteria will be made available by the ERCOT without conditions to FERC and to the public per the procedures stated below.
Mailing address, contact person and title, telephone and facsimile numbers:
Electric Reliability Council of Texas Inc.
Independent System Operator
2705 West Lake Drive
Taylor, Texas 76574-2136
Ken Donohoo
Sr. Transmission Systems Engineer
Tel: (512) 248-3003
Fax: (512) 248-3095
Process for public access to ERCOT Reliability Criteria:
Requested data will be sent no later than 10 working days following receipt of the written request by the regional contact person. The fee is $100.00 for a printed copy. Shipping costs and sales tax, when applicable, will be added.
The transmission planning function responsibility for CPL and WTU moved to Central and South West Services, Inc. (CSWS) in 1994. Common transmission reliability criteria for both CPL and WTU have been developed and are included in this report. CSWS complies with the ERCOT Reliability Criteria, the NERC Principles, Criteria, Standards, and Guides and the Central and South West Transmission Reliability Criteria as the basis for the planning and design of the CPL and WTU transmission systems.
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
18 CFR Part 141.300
FERC FORM NO. 715
Annual Transmission Planning and Evaluation Report
For the Year Ending December 31, 1999
Part 4: Transmission Planning Reliability Criteria
PSO and SWEPCO are both members of the Southwest Power Pool (SPP), and as a condition of membership have agreed to conform with all approved and applicable SPP and the North American Electric Reliability Council (NERC) Principles, Criteria, Standards, and Guides. The SPP Reliability Criteria and Guides have been supplied to the Office of Energy Emergency Operations, Department of Energy under EIA-411 dated April 1, 1999. The updated 1999 Criteria will be supplied by April 1, 2000. The SPP Reliability Criteria and Guides will be made available by the SPP without conditions to FERC and to the public per the procedures stated below.
Mailing address, contact person and title, telephone and facsimile numbers:
Southwest Power Pool, Inc.
415 North McKinley Street
Plaza West Building - #700
Little Rock, Arkansas 72205-3020
Nicholas A. Brown, P.E.
Vice President
Telephone: (501) 664-0146 ext. 213
Facsimile: (501) 664-9553
Process for public access to SPP Reliability Criteria:
Hard copy information will be sent via first class U.S. Mail no later than 10 working days following receipt by the above contact person of a written request and pre-paid fee of $60.
The transmission system planning function responsibility for PSO and SWEPCO moved to Central and South West Services, Inc. (CSWS) in 1994. Common, specific transmission reliability criteria for both PSO and SWEPCO has been developed and is included in this report. CSWS generally follows the SPP Reliability Criteria and Guides, the NERC Principles, Criteria, Standards, and Guides and the Central and South West Transmission Planning Reliability Criteria as the basis for the planning and design of the PSO and SWEPCO transmission systems.
Central and South West
Transmission Planning Reliability Criteria
CSW’s power system transmission lines and substations at voltages 69 kV and above are used to transfer power from generating stations to load centers or to interconnect with other electric utilities for the purpose of making power transfers and improving system reliability. CSW uses Good Utility Practice to ensure its transmission system is in compliance with either the Electric Reliability Council of Texas (ERCOT) or the Southwest Power Pool (SPP) Reliability Criteria, and NERC Planning Standards as applicable, as well as the specific criteria listed below.
1. Nominal Voltage Levels
Nominal 345 kV, 161 kV and 138 kV voltage levels will normally be used for most new power transmission lines. Some interconnection lines may be at 115 kV, 230 kV, or 500 kV to match the other utility's voltage and some 69 kV lines may be constructed in appropriate situations.
2. Voltage regulation
(a) Generation voltage is generally scheduled to hold higher than nominal generator voltage during peak load periods and thus stabilize the power transmission system voltages.
(b) Capacitor banks, reactors, and LTC auto-transformers are used in transmission substations to hold voltage levels within acceptable ranges during normal and emergency conditions.
(c) System conditions must be controlled so as to prevent excessive LTC tap changes.
(d) Static Var Compensators, synchronous condensers, stored energy devices, and series compensation may be used under special conditions.
3. Voltage Limits
(a) Transmission voltages should not exceed 105% nor fall below 95% of the nominal voltages shown above during normal operation of the system.
(b) Transmission voltages during emergencies should not exceed equipment overexcitation ratings.
(c) Transmission voltages during emergencies should not result in customer voltages exceeding or falling below prescribed limits at distribution substations on the transmission system.
(d) Transmission voltage should not exceed 105% nor fall below 90% of nominal voltage shown above during emergencies. The low limit can be lower if voltage regulating equipment maintains voltage to the customers within prescribed limits at distribution substations involved without causing voltage problems at nearby loads.
(e) Voltage flicker on the transmission system (such as those caused by motor starting, capacitor or reactor switching, furnace loads, drag lines and other intermittent or varying real and reactive loads) will be dictated by the sensitivity of the load or loads being served. The attached chart is a modified version of the ANSI/IEEE (Std. 141-1993) Voltage Flicker Chart listed in the IEEE Red Book.
4. Thermal Capabilities of Transmission Facilities
(a) Transmission Lines
(1) Existing transmission lines were designed to meet operating standards that were in effect at the time the line was built. The National Electric Safety Code (NESC) specified the maximum conductor temperature which maintained acceptable ground clearance while allowing for acceptable loss of conductor tensile strength. CSWS Transmission Planning will use thermal ratings established by CSWS Transmission Design that are consistent with the NESC design standards being practiced at the time the line was built.
(2) The thermal capabilities are generally assigned as shown on the following sheets of conductor ratings for existing transmission and future transmission lines. Lines with design constraints will be rated at actual design limits.
(3) The circuit thermal capabilities should be reduced to the rating of the substation terminal equipment if the ratings of that equipment are lower than the conductor ratings. In general, substation terminal equipment should be sized to match or exceed conductor ratings.
(4) The emergency rating for transmission lines are for eight (8) hours.
(b) Autotransformers
(1) The normal rating for autotransformers shall be its top name plate rating, including the effects of forced cooling equipment if it is available.
(2) The emergency rating for autotransformers shall be 110% of its top name plate rating for the first four (4) hours of emergency and 100% thereafter.
(c) Disconnect Switches
The normal and emergency rating shall be 100% of name plate rating.
(d) Wave Traps
The emergency rating shall be 110% of name plate rating.
(e) Current Transformers
The normal rating shall be 1.5 times the primary current rating of the CT. The 4 hour emergency rating shall be 10% greater than the normal rating.
(f) Circuit Breakers
The normal and emergency rating shall be 100% of name plate rating.
5. Reactive Power Capability
Reactive power resources will be provided in amounts which are sufficient for system voltage control under normal and contingency conditions, including the dynamic period following system disturbances. Each CSW operating company or control area is responsible for providing or arranging for the provision of reactive power reasonably adequate to supply both its own reactive power load and any reactive power losses associated with service to its transmission service load, whether such losses are incurred on its own system or the facilities of others. Reactive power resource planning will be coordinated by the CSWS Transmission Planning Department with the Operating Companies.
The power factor for each operating company and its major sub-areas will be maintained as follows:
(a) The overall system power factor range should be maintained at 99-100% lagging. This will be calculated from the net MW and Mvar flows on the high side of the generator step-up transformer, and at the interconnections. A net power factor of 97%-100% lagging should be maintained on the generator side of the step-up transformer.
(b) Leading power factor on generators will normally be used only for off-peak, low load situations for limited amounts of time, to reduce the likelihood of generator instability.
6. Transmission Capacity and Load at Risk
(a) Transmission capacity of individual power transmission lines is planned so generation can be economically scheduled for all load levels with all lines in service with consideration of the cost of transmission losses and future loading of the lines.
(b) With one line out of service, no generation curtailment should be necessary.
(c) The minimum transmission capacity to a major transmission substation will be maintained at the substation rating with the largest incoming line out of service.
(d) Any general distribution load in excess of 12 MW should have redundant transmission service, unless the load at risk can be transferred to other sources within 24 hours of interruption.
(e) Any load in excess of 100 MW, or any series of four or more inline substations with load in excess of 12 MW each, should have redundant transmission service, and be sectionalized by circuit breakers, unless transmission facilities are customer dedicated, or unless the load at risk can be transferred momentarily and automatically at the distribution voltage.
7. Stability
(a) The power transmission system is planned to be stable for all transmission line faults which are cleared in normal clearing times.
(b) Stability will be maintained for phase-to-ground and phase-to-phase faults which are cleared by stuck breaker relaying or backup relaying with primary relaying out of service.
8. Reliability
(a) More probable contingency testing shall investigate the following situations:
(1) Loss of any single critical transmission line,
(2) Loss of any single transformer,
(3) Loss of any bus section,
(4) Loss of any double circuit line of one mile or greater length,
(5) Loss of any tie breaker,
(6) Loss of any generating unit, and
(b) For the occurrence of any of the above more probable contingencies, testing must conclude that:
(1) All facility loadings are within their emergency ratings and all voltages are within their emergency limits, and
(2) Facility loadings can be returned to their normal limits within four hours.
(c) Less probable contingency testing shall investigate the following situations:
(1) Loss of any combination of related facilities, a critical transmission line when a 345 kV auto-transformer is out of service, or a generating unit when another generating unit is out of service.
(2) Sudden outage of any multi-circuit transmission line at a time when any other single circuit is out of service,
(3) Sudden outage of any single or double-circuit transmission tower line at a time when two generating units are out of service, for maintenance or economics,
(4) Sudden outage of any generating unit at a time when any two other generating units are out of service for maintenance or economics,
(5) Sudden outage of all generating units at any plant,
(6) Sudden outage of all transmission lines on the same right-of-way,
(7) Sudden outage of any transmission station including all generating capacity associated with such a station,
(8) Sudden dropping of a large load or a major load center, and
(9) Any other credible contingent scenario which might lead to cascading outages.
(d) For the occurrence of any of the above less probable contingencies, testing must conclude that neither uncontrolled islanding, nor uncontrolled loss of large amounts of load will result.
9. Transfer Capability
Adequate transfer capability between CSW and outside systems shall be maintained over and above any existing or future firm transactions while meeting the applicable reliability council planning criteria. The following guidelines are applied in determining adequate transfer capability:
(a) Each operating company or load center within the CSW transmission network must be able to import an amount of power at least equal to the sum of 1, 2, and 3 below, while maintaining all facilities within their emergency ratings, and maintaining voltages within emergency limits during any of the more probable contingencies listed in section 8.
(1) Remote generation which the operating company owns,
(2) Any firm purchases, and
(3) Largest generating unit within the area
(b) Each operating company will maintain an import capability sufficient to support a loss of load expectation index of no greater than 0.1 indicating that load will exceed generation no more than one day in 10 years.
(c) The operating company must have an export capability with the rest of the reliability council as a whole that is equivalent to, as a minimum, the operating company's planned internal on-line operating reserve obligation plus any long term firm transmission service contracts in effect.
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| | | | |
|Category |Contingencies | |System Limits or Impacts |
| | | | | | | | |
| | |Components |Thermal |Voltage |System |Loss of Demand or |Cascading c |
| |Initiating Event(s) and Contingency Component(s) |Out of Service |Limits |Limits |Stable |Curtailed Firm Transfers |Outages |
| | | | | | | | |
|A – No |All Facilities in Service |None |Normal |Normal |Yes |No |No |
|Contingencies | | | | | | | |
| | | | | | | | |
|B – Event |Single Line Ground (SLG) or 3-Phase (3Ø) Fault, with Normal Clearing: | |Applicable Rating |Applicable Rating| | | |
|resulting in |1. Generator |Single |a (A/R) |a (A/R) |Yes |No b |No |
|the loss of a |2. Transmission Circuit |Single |A/R |A/R |Yes |No b |No |
|single |3. Transformer |Single |A/R |A/R |Yes |No b |No |
|component. |Loss of a Component without a Fault. |Single |A/R |A/R |Yes |No b |No |
| | | | | | | | |
| |Single Pole Block, Normal Clearing: | | | | | | |
| |4. Single Pole (dc) Line |Single |A/R |A/R |Yes |Nob |No |
| | | | | | | | |
|C – Event(s) |SLG Fault, with Normal Clearing: | | | | | | |
|resulting in |1. Bus Section |Multiple |A/R |A/R |Yes |Plannedd |No |
|the loss of |2. Breaker (failure or internal fault) |Multiple |A/R |A/R |Yes |Plannedd |No |
|two or more | | | | | | | |
|(multiple) | | | | | | | |
|components. | | | | | | | |
| | | | | | | | |
| |SLG or 3Ø Fault, with Normal Clearing, Manual System Adjustments, followed | | | | | | |
| |by another SLG or 3Ø Fault, with Normal Clearing: | | | | | | |
| |3. Category B (B1, B2, B3, or B4) contingency, manual system adjustments, | | | | | | |
| |followed by another Category B (B1, B2, B3, or B4) contingency |Multiple |A/R |A/R |Yes |Plannedd |No |
| | | | | | | | |
| |Bipolar Block, with Normal Clearing: | | | | | | |
| |4. Bipolar (dc) Line |Multiple |A/R |A/R |Yes |Plannedd |No |
| |Fault (non 3Ø), with Normal Clearing: |Multiple |A/R |A/R |Yes |Plannedd |No |
| |5. Double Circuit Towerline | | | | | | |
| | | | | | | | |
| |SLG Fault, with Delayed Clearing: | | | | | | |
| |6. Generator 8. Transformer |Multiple |A/R |A/R |Yes |Plannedd |No |
| |7. Transmission Circuit 9. Bus Section |Multiple |A/R |A/R |Yes |Plannedd |No |
| | | |
| | | |
| | | |
|D e – Extreme |3Ø Fault, with Delayed Clearing (stuck breaker or protection system failure):|Evaluate for risks and consequences. |
|event |1. Generator 3. Transformer | |
|resulting in |2. Transmission Circuit 4. Bus Section |May involve substantial loss of customer demand and generation in a widespread area or areas. |
|two or more | |Portions or all of the interconnected systems may or may not achieve a new, stable operating point. |
|(multiple) |3Ø Fault, with Normal Clearing: |Evaluation of these events may require joint studies with neighboring systems. |
|components |5. Breaker (failure or internal fault) |Document measures or procedures to mitigate the extent and effects of such events. |
|removed or | |Mitigation or elimination of the risks and consequences of these events shall be at the discretion of the |
|cascading out |Other: |entities responsible for the reliability of the interconnected transmission systems. |
|of service |6. Loss of towerline with three or more circuits | |
| |7. All transmission lines on a common right-of way | |
| |8. Loss of a substation (one voltage level plus transformers) | |
| |9. Loss of a switching station (one voltage level plus transformers) | |
| |10. Loss of a all generating units at a station | |
| |11. Loss of a large load or major load center | |
| |12. Failure of a fully redundant special protection system (or remedial | |
| |action scheme) to operate when required | |
| |13. Operation, partial operation, or misoperation of a fully redundant | |
| |special protection system (or remedial action scheme) for an event or | |
| |condition for which it was not intended to operate | |
| |14. Impact of severe power swings or oscillations from disturbances in | |
| |another Regional Council. | |
Footnotes to Table I.
a) Applicable rating (A/R) refers to the applicable normal and emergency facility thermal rating or system voltage limit as determined and consistently applied by the system or facility owner.
b) Planned or controlled interruption of generators or electric supply to radial customers or some local network customers, connected to or supplied by the faulted component or by the affected area, may occur in certain areas without impacting the overall security of the interconnected transmission systems. To prepare for the next contingency, system adjustments are permitted, including curtailments of contracted firm (non-recallable reserved) electric power transfers.
c) Cascading is the uncontrolled successive loss of system elements triggered by an incident at any location. Cascading results in widespread service interruption which cannot be restrained from sequentially spreading beyond an area predetermined by appropriate studies.
d) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers (load shedding), the planned removal from service of certain generators, or the curtailment of contracted firm (non-recallable reserved) electric power transfers may be necessary to maintain the overall security of the interconnected transmission systems.
e) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed contingency of Category D will be evaluated.
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* However, notwithstanding any other provision of this Operating Agreement, the Transmission Provider shall retain the sole responsibility and authority for operating decisions as they relate to the integrity and security of the Transmission System.
[1] This includes mitigation of contingency overloads.
[2] Examples would be 1) a local procedure that curtails Interchange Transactions in a different order or ratio than the Interconnection-wide procedure, or 2) a local redispatch procedure.
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Transmission Service Priorities
Priority 0. Next-hour Market Service – NX*
Priority 1. Service over secondary receipt and delivery points – NS
Priority 2. Hourly Service – NH
Priority 3. Daily Service – ND
Priority 4. Weekly Service – NW
Priority 5. Monthly Service – NM
Priority 6. Network Integration Transmission Service from sources not designated as network resources – NN
Priority 7. Firm Point-to-Point Transmission Service and Network Integration Transmission Service from Designated Resources – F
*NX is Pending FERC Approval
For implementation
February 15, 2000
Operating Companies of the Original Sheet No. 291
American Electric Power System
FERC Electric Tariff, Second Revised Third RevisedVolume No. 6
Issued by: William J. Lhota, Executive Vice PresidentJ. Craig Baker, Effective: June 15, 2000July 31,
Senior Vice President-Regulation and Public Policy 2001 or when ERCOT begins control
Issued on: August 24, 2000July 23, 2001 area operations, if later
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