New Brunswick Electricity Business Rules

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1 New Brunswick Electricity Business Rules Table of Contents Chapter 1 Chapter 2 Chapter 3 Chapter 4 Administration and Participation Transmission Planning and Connections Reliable Operations Billing and Payment Appendices Appendix A Appendix B Appendix C Appendix D Appendix E Appendix F Appendix G Definitions Connection Assessment Procedure Balanced Schedule Submission Third Party Generator Dispatch Data Submission Ancillary Services Operational Requirements Reliability Requirements NPCC Criteria and Directions Tariff and OASIS Administrative Practices

2 New Brunswick Electricity Business Rules Chapter 1 Administration and Participation

3 Business Rules Chapter 1 Administration and Participation TABLE OF CONTENTS CHAPTER 1 ADMINISTRATION AND PARTICIPATION Authority and Scope Purpose of the Business Rules Applicability Amendments and Publication Waivers from the Business Rules Confidentiality Dispute Resolution Sanctions Force Majeure and Indemnification Definitions... 7

4 Business Rules Chapter 1 Administration and Participation CHAPTER 1 ADMINISTRATION AND PARTICIPATION 1.0 Authority and Scope The authority and scope of the Electricity Business Rules (the Business Rules ) are established in the Electricity Act. The Business Rules complement and supplement the Open Access Transmission Tariff (the Tariff ), and facilitate the reliable operation of the Integrated Electricity System (the IES ) and adherence to Board Approved Reliability Standards The operation of the IES is governed by the Electricity Act, the Tariff, and the Business Rules The Transmission Provider shall administer the Business Rules If a conflict exists between a provision of the Business Rules and a provision of Tariff the provision of the Tariff prevails If a conflict exists between a provision of the Business Rules and a Board Approved Reliability Standard the more stringent provision prevails. 1.1 Purpose of the Business Rules The purpose of the Business Rules is to clarify and provide interpretation regarding the rights and obligations between the Transmission Provider and transmission system users with respect to the administration of the Tariff, the operation of the IES, and functions performed by the Transmission Provider with respect to electricity systems outside of New Brunswick The Business Rules define the administrative practices for the sale and provision of Transmission Services. The Transmission Provider offers Transmission Service in accordance with the rates, terms, and conditions contained in the Tariff, a copy of which is posted on the Transmission Provider s public website. Version: 01 Page 2

5 Business Rules Chapter 1 Administration and Participation The Transmission Provider offers both Point-to-Point Transmission Service and Network Integration Transmission Service under the Tariff. The terms and conditions for these Transmission Services are contained in Parts II and III of the Tariff. The Tariff also contains terms and conditions for Transmission Customers use of Ancillary Services. 1.2 Applicability Respecting sections and 1.2.4, the Business Rules apply to the following entities, hereinafter referred to as Transmission Users: Transmission Provider Transmission Customers Compliance registrants for Board Approved Reliability Standards Those Facilities deemed by the Transmission Provider to materially impact reliability of the IES External entities utilizing the services of or providing services to the Transmission Provider through: o Interconnection agreements o Application of NERC defined functions (e.g. Reliability Coordinator, Balancing Authority) In the event that any of these entities identifies an actual or potential conflict between the Tariff (including schedules and attachments), the Standards of Conduct, a rate approved by the Board or an order of the Board and the Business Rules, it shall notify the Transmission Provider and seek clarification or appropriate correction Any person that conveys or causes electricity to be conveyed into, through, or out of the IES shall do so in accordance with the Business Rules Any person that provides or causes ancillary services to be provided into, through, or out of the IES shall do so in accordance with the Business Rules. Version: 01 Page 3

6 Business Rules Chapter 1 Administration and Participation 1.3 Amendments and Publication The Transmission Provider has the exclusive authority to amend the Business Rules. This authority shall be exercised in accordance with the Electricity Act Other than in the case of Urgent Amendments, amendments to the Business Rules shall be made as follows: Proposals for amendments may be made by any party through a submission to the Transmission Provider. Proposed amendments will be published by the Transmission Provider, at least 30 day before the amendments come into force, in advance of any decision to adopt the proposed changes. Transmission Provider shall make provision for comments on proposed amendments (other than Urgent Amendments), and comments that are received by the Transmission Provider shall be published by the Transmission Provider The Transmission Provider has the right to make Urgent Amendments in accordance with the Electricity Act. Although not a requirement, the conditions in Section shall be treated as guidelines when making such Urgent Amendments In accordance with the Electricity Act, on application by any person the Board shall review any amendment to the Business Rules The Transmission Provider shall maintain a current version of the Business Rules on its public website and shall make the Business Rules available for public inspection during normal business hours. 1.4 Waivers from the Business Rules Any party may apply to the Transmission Provider for a waiver from any provision of the Business Rules. Version: 01 Page 4

7 Business Rules Chapter 1 Administration and Participation An application for a waiver shall be made to the Transmission Provider via a letter signed by an officer of the requesting party. The Transmission Provider may only grant waivers from the Business Rules when not doing so would cause unjust, material, and irreparable harm to the requesting party. Any waiver granted in whole or in part and any terms and conditions imposed by the Transmission Provider shall be on a not unduly discriminatory or preferential basis, and the same waiver shall be available to similarlysituated customers All applications for waivers, granting of waivers in whole or in part along with any terms and conditions, and denials of waivers including rationale shall be Published. In each case, the Published material shall clearly identify the requesting party and the rationale behind the request and its approval or denial. The Published material may contain redactions as required to protect commercially sensitive information Disputes to requests, approvals, or denials of waivers are to be addressed in accordance with the dispute resolution process identified in section 1.6 and can be initiated by any party The applicant or any person affected by a decision made by the Transmission Provider in respect of the application may appeal the decision to the Board in accordance with the Act. 1.5 Confidentiality Information disclosed or provided by a Transmission Customer, a Transmitter or the Transmission Provider under the Business Rules shall be, to the best of the disclosing person s knowledge, true, correct and complete. No one shall knowingly or recklessly disclose or provide any information that is expressly or by omission misleading or deceptive. When it is discovered that any information disclosed or provided under the Business Rules has become untrue, incorrect, incomplete, misleading or deceptive, the disclosing party shall promptly rectify the situation The Transmission Provider is entitled to use any data or information obtained in the performance of its functions. Such use may be for any purpose contemplated under the Version: 01 Page 5

8 Business Rules Chapter 1 Administration and Participation Business Rules, the Electricity Act, or as directed by the Board. Such use must not contravene the Standards of Conduct No party shall disclose or provide access to Confidential Information except as permitted by the Business Rules. Such disclosure or access to Confidential Information must not contravene the Standards of Conduct. No party shall use or reproduce such information other than for the purpose for which it was disclosed or another purpose contemplated by the Business Rules. 1.6 Dispute Resolution The settlement of disputes associated with the Business Rules shall be addressed through the dispute resolution process contained in the Tariff In accordance with the Act any person that is subject to an order or decision of the Transmission Provider made under the Business Rules may appeal the order or decision to the Board. 1.7 Sanctions Where a breach of the Business Rules results in a risk to Reliability or could reasonably be expected to adversely impact Reliability, the Transmission Provider may take all actions necessary to resolve the situation, including the imposition of operational restrictions up to and including disconnection, on a non-discriminatory basis in accordance with the Tariff, applicable connection agreements and Good Utility Practice. 1.8 Force Majeure and Indemnification The transmission system users identified in section shall hold the Transmission Provider harmless with respect to its performance of obligations under the Business Rules in the same fashion as the Transmission Customer is required in the Tariff to hold the Transmission Provider harmless with respect to the Transmission Provider s performance of its obligations under the Tariff. Version: 01 Page 6

9 Business Rules Chapter 1 Administration and Participation 1.9 Definitions Defined terms used in the Business Rules are capitalized. Definitions for these terms are listed in Appendix A. Version: 01 Page 7

10 New Brunswick Electricity Business Rules Chapter 2 Transmission Planning and Connections

11 Chapter 2 Transmission Planning and Connections TABLE OF CONTENTS CHAPTER 2 TRANSMISSION PLANNING AND CONNECTIONS ROLES AND RESPONSIBILITIES TRANSMISSION SYSTEM PLANNING, INVESTMENT AND OPERATIONS CONNECTION OF NEW AND MODIFIED FACILITIES... 6

12 Chapter 2 Transmission Planning and Connections CHAPTER 2 TRANSMISSION PLANNING AND CONNECTIONS The provisions of Chapter 2 are intended to take effect as Electricity Business Rules (the Business Rules ) on an interim basis during the period in which the transitional Open Access Transmission tariff (the Tariff ) will be in effect under the Electricity Act. The Transmission Provider intends to amend the Business Rules in Chapter 2, in conjunction with the new Tariff filing required to be made within one year of the effective date of the Electricity Act. The Business Rules changes that are made at that time will reflect and complement any Board rulings with respect to transmission planning. The changes, where appropriate, will include moving provisions of these Chapter 2 Business Rules into the new Tariff or an Attachment. 2.0 ROLES AND RESPONSIBILITIES The Transmission Provider is responsible for planning and coordinating all changes to the Integrated Electrical System (the IES ). In doing so, the Transmission Provider will maintain and ensure the Adequacy and Reliability of the IES The Transmission Provider is responsible to ensure that the transmission planning process allows for an efficient, non-discriminatory, coordinated and transparent forum open to all existing and prospective Transmission Customers. The Transmission Provider's process and its conduct shall be consistent with its Standards of Conduct The Transmission Provider may establish Adequacy criteria for the IES. Such criteria shall be included in the Reliability Requirements of section 3.7, or the Transmission Provider's transmission planning criteria The Transmission Provider shall work with responsible authorities including those outside of New Brunswick to coordinate the Transmission Provider s planning activities with their activities. Version: 01 Page 2

13 Chapter 2 Transmission Planning and Connections 2.1 TRANSMISSION SYSTEM PLANNING, INVESTMENT AND OPERATIONS Long-term Integrated Electricity System Development Plan In each calendar year the Transmission Provider shall prepare and publish a plan for the development of the IES, referred to as the 10-Year Outlook. Each plan shall cover at least the following ten years, commencing on April 1 of the calendar year in which the plan is Published Upon completion of the 10-Year Outlook, the Transmission Provider shall, at a minimum: a) Publish the 10-Year Outlook; b) Notify Transmission Customers of the publication of the document; c) Solicit comments on the contents of the 10-Year Outlook; d) Host an open session for discussion of the 10 Year Outlook within 30 days of its publication, having provided Transmission Customers with at least 14 days notice; e) Reflect comments received within 45 days of the Publication of the 10-Year Outlook in a Published summary of comments; f) Publish a revised 10-Year Outlook if required to correct material errors, omissions; and compelling requests for enhancements; and g) Ensure that relevant comments are reflected in subsequent 10-Year Outlooks The 10-Year Outlook is generally comprised of: a) The basic methodology, criteria, and processes used to develop transmission plans; b) The Baseline Plan as described in section 2.1.2; c) The summarized results of studies performed under section 2.1.3; Version: 01 Page 3

14 Chapter 2 Transmission Planning and Connections d) The summarized results of other non-confidential studies of the Integrated Electricity System; and e) The identification of upgrades as committed pending Board approval, under study, or proposed Nothing in this section shall prevent the Transmission Provider from preparing, in addition to the 10-Year Outlook, alternative plans based on differing assumptions as to the likelihood of implementation of the connection of new or modified Facilities to the IES Baseline Plan The Transmission Provider shall prepare each Baseline Plan using: a) Data and information submitted by Transmission Customers under section 3.1, Reliability Assessments; b) Information contained in Requests for Connection Assessment filed with the Transmission Provider under the Tariff; c) The preceding year s Baseline Plan prepared under this section; d) Data received from Transmitters that own or operate neighbouring transmission systems; and e) Such other information as the Transmission Provider considers appropriate Each Baseline Plan shall reflect: a) Committed and scheduled investments in Transmission Facilities and Transmission System expansion plans; b) All connections of new or modified Facilities that have been approved by the Transmission Provider; and Version: 01 Page 4

15 Chapter 2 Transmission Planning and Connections c) All investments in Transmission Facilities required for reasons of Reliability of the IES The Transmission Provider shall use the Baseline Plan as the basis for the determination of incremental, decremental, deferred, or advanced costs as required in allocating costs associated with transmission expansion. Any such allocation shall be performed in compliance with the Tariff Assessment of Adequacy of the Integrated Electricity System The Transmission Provider shall perform an annual assessment to identify the potential need for investments in Transmission Facilities and other actions that may be required to maintain Reliability of the IES, and to reduce the costs associated with transmission constraints on the IES. Where applicable, each such annual assessment shall identify the impact of existing and emerging shortages of transmission capacity on the IES, any significant existing, emerging or potential transmission constraints on the IES, the impact of the connection of new or modified Facilities and the Adequacy of Interconnections Where the Transmission Provider has identified in an annual assessment the need to alleviate an existing or emerging transmission constraint on the IES, it shall develop and study technically feasible options for alleviating the constraint in consultation with existing and potential Transmission Customers Each calendar year, Transmission Customers are requested to submit to the Transmission Provider any projections that identify a need for Transmission service over the next 10 years. Such good faith projections of a need for service, even though they may not yet be subject to a transmission reservation, are useful in transmission planning. Such projections may be used to determine potential transmission constraints on the IES. Version: 01 Page 5

16 Chapter 2 Transmission Planning and Connections Where an annual assessment referred to in section identifies a potential transmission constraint on the IES, the Transmission Provider may, depending upon the nature and the probability of the constraint, a) utilize the process as described in section ; or b) request further supporting information For the purposes of this section a transmission constraint shall be considered to be emerging if it is identified by the Transmission Provider as likely to arise within one to five years and a transmission constraint shall be considered to be potential if it is identified by the Transmission Provider as likely to arise, which may be based upon good faith projections of transmission customers of section , within five to ten years. 2.2 CONNECTION OF NEW AND MODIFIED FACILITIES Connection Requirements of New and Modified Facilities All new or modified Facilities must be approved by the Transmission Provider before connecting to the IES Each Generation Facility that is connected to the IES must be the subject of a Connection Agreement in substantially the form of the agreement set forth in Attachment J, Generation Connection Agreement, of the Tariff Each Load Facility, including for greater certainty a Distribution System, that is connected to the IES must be the subject of a connection agreement with the applicable Transmitter in substantially the form of the Attachment G, Network Operating Agreement, set forth in the Tariff. Power supply agreements between the Corporation and Load Facilities connected at the time the Business Rules came into effect are deemed to qualify to fulfill this obligation. Version: 01 Page 6

17 Chapter 2 Transmission Planning and Connections Each new Facility that is connecting to the IES shall comply with the applicable technical requirements defined in the Transmission Provider s Facility Connection Requirements General Connection Assessment Process for New or Modified Generation and Interconnection Facilities A person that wishes to connect a new or modified Facility to the IES shall file a Request for Connection Assessment with the Transmission Provider in the form set forth in Appendix B, Connection Assessment Procedure, together with the supporting materials and deposit Without a request for Transmission Service a new generation connection request is exploratory in nature and does not entail any commitment on behalf of the Transmission Provider for Transmission Service. Formal requests for a transmission service must come in the form of a Transmission Service request under the terms and conditions of the Tariff. In this section, approval of a new generation connection request is conditional on such service request The Transmission Provider shall assign a priority to each Request for Connection Assessment that it receives based on the date of receipt of the completed Request for Connection Assessment and in accordance with Appendix B of the Business Rules. Requests for Transmission Service shall be processed in accordance with the Tariff with further detail provided in Appendix B Following receipt and review of a completed Request for Connection Assessment, the Transmission Provider will approve the request or conduct a Feasibility Review in respect of the connection of the new or modified Facility where the Transmission Provider considers whether such connection: a) May have an adverse impact on the Reliability of the IES; or Version: 01 Page 7

18 Chapter 2 Transmission Planning and Connections b) May create a probability of additional constraints by causing the IES to operate at or close to its normal operating limits Where the Transmission Provider concludes in its Feasibility Review that the connection of the new or modified Facility to the IES will not have either of the effects referred to in sections (a) and (b), the Transmission Provider shall approve the request Where the Transmission Provider concludes in its Feasibility Review that the connection of a new or modified Facility to the IES will have an adverse impact on the Reliability of the IES in a Proximate Area only, the Transmission Provider shall: a) Identify the upgrades to the elements of the IES in the Proximate Area that are required to mitigate the adverse impact of the connection of the new or modified Facility on the Reliability of the IES; and b) Approve the connection of the new or modified Facility upon receipt of an undertaking by the Connection Applicant to pay its portion of the costs of such upgrades as assigned or allocated by the Transmission Provider in accordance with the Tariff Where the Transmission Provider concludes in its Feasibility Review that the connection of the new or modified Facility to the IES may have (i) an adverse impact on the Reliability of the IES beyond a Proximate Area; or (ii) the effect referred to in section (b), the Transmission Provider shall conduct a System Impact Study. Where the Transmission Provider conducts a System Impact Study and concludes that the connection of the new or modified Facility: a) will have an adverse impact on the reliability of the IES, then the Transmission Provider shall not approve the connection unless the Connection Applicant agrees, in a form satisfactory to the Transmission Provider, to bear its portion of the costs of all upgrades to the IES that may Version: 01 Page 8

19 Chapter 2 Transmission Planning and Connections be required to mitigate such adverse Reliability impact as assigned or allocated by the Transmission Provider in accordance with the Tariff; or b) if the Facility is a Generation Facility, will create the probability of additional constraints by causing the IES to operate at or close to its normal operating limits, then the Transmission Provider shall not approve the connection unless: i. where the Transmission Provider is satisfied that the imposition of conditions on the operation of the new or modified Facility can mitigate the probability of such additional constraints, the Connection Applicant agrees to include in its Generation Connection Agreement provisions that require the Connection Applicant to operate the new or modified Facility in accordance with those conditions; ii. in all other cases, the Connection Applicant agrees, in a form satisfactory to the Transmission Provider, to bear its portion of the costs of all upgrades to the IES that may be required to mitigate the probability of such additional constraints as assigned or allocated by the Transmission Provider in accordance with the Tariff Where the Transmission Provider determines that it will not approve the connection of a new or modified Facility to the IES under section (a), the Connection Applicant may modify its connection proposal and request that the Transmission Provider conduct a new System Impact Study on the basis of the modified connection proposal. A change in Point-of-Receipt/Point-of-Delivery will be treated as a new proposal for queuing purposes. Version: 01 Page 9

20 Chapter 2 Transmission Planning and Connections General Connection Assessment Process for New or Modified Load Facilities A person that wishes to connect a new or modified Load Facility to the IES shall file a Request for Connection Assessment with the Transmission Provider in the form set forth in Appendix B, Connection Assessment Procedure, together with the supporting material Relating to section , for modified facilities, the Transmission Provider will advise the Connection Applicant if the modification may be materially impactive requiring such submission for preliminary review and, as necessary, an in-depth review Following receipt of a completed Request for Connection Assessment and subsequent preliminary review the Transmission Provider will either a) Approve the request; or b) Conduct an in-depth review where the impact of such connection may have an adverse impact on the Reliability of the IES Where the Transmission Provider concludes that the connection of the new or modified Facility does not have adverse impact on the IES the Transmission Provider will approve the request. Otherwise the Transmission Provider shall: a) Identify the upgrades to the elements of the IES that are required to mitigate the adverse impact of the connection of the new or modified Facility on the Reliability of the IES; and b) Approve the connection of the new or modified Facility upon receipt of an undertaking by the Connection Applicant to pay its portion of the costs of such upgrades in accordance with the Tariff. Where the Transmission Provider, in consultation with the Connection Applicant, determines that such a connection is not practical the Connection Applicant may Version: 01 Page 10

21 Chapter 2 Transmission Planning and Connections modify its connection proposal and request that the Transmission Provider conduct a new review on the basis of the modified connection proposal. A modified connection proposal will be treated as a new request for queuing purposes Costs of Connection Assessments The Transmission Provider shall invoice a Connection Applicant for the costs incurred by the Transmission Provider in conducting a Feasibility Review in respect of the Connection Applicant s Request for Connection Assessment, less the amount paid by the Connection Applicant as a deposit required by Appendix B The Transmission Provider shall invoice a Connection Applicant for: a) the costs incurred by the Transmission Provider in conducting a System Impact Study in respect of the Connection Applicant s Request for Connection Assessment, less the amount paid by the Connection Applicant as a deposit as per Appendix B, where the System Impact Study relates solely to such Request for Connection Assessment; or b) for the Connection Applicant s share of the costs incurred by the Transmission Provider in conducting a System Impact Study in respect of the Connection Applicant s Request for Connection Assessment, less the amount paid by the Connection Applicant as a deposit as per Appendix B, where the System Impact Study relates to such Request for Connection Assessment and to one or more other Requests for Connection Assessment. Such share shall be determined by the Transmission Provider in accordance with Appendix B An invoice referred to in section or , shall include any costs incurred by a Transmitter in complying with a request for assistance under Section An invoice referred to in section or , shall be payable in full by the Connection Applicant within 20 Business Days of the date of the invoice. For greater Version: 01 Page 11

22 Chapter 2 Transmission Planning and Connections certainty, such invoice shall be considered to create an obligation under the Business Rules to pay the amount stated in the invoice and such amount may, without prejudice to any other manner of recovery available at law, be recovered accordingly The principles of cost sharing as described in the Tariff, Attachment K, Transmission Expansion Policy, shall also apply to the Connection Assessment Costs Allocation of Costs of Connection and of Associated Changes to the IES The allocation of the costs of connections and of associated changes to the IES shall be in accordance with the Tariff Implementation of Connection Each Connection Applicant shall ensure that the connection of its new or modified Facility is effected in a manner that does not represent a material change from: a) any technical requirements that are identified in the applicable Connection Assessment as being required to be met in respect of the connection of the new or modified Facility; or b) the configuration or technical parameters that were used by the Transmission Provider as the basis upon which it approved such connection or that were imposed as a condition in approval of such connection, unless the Connection Applicant has obtained the prior approval of the Transmission Provider for the material change The Transmission Provider shall approve a material change referred to in section , unless it determines that such deviation will have an adverse effect on the reliability of the IES. Where the Transmission Provider does not approve such a material change, the Connection Applicant may propose to the Transmission Provider measures designed to mitigate the adverse effects of the material change on the Reliability of the IES. Version: 01 Page 12

23 New Brunswick Electricity Business Rules Chapter 3 Reliable Operations

24 Chapter 3 Reliable Operations TABLE OF CONTENTS CHAPTER 3 RELIABLE OPERATIONS System Operator Roles and Responsibilities Reliability Assessments Ancillary Services Scheduling and Dispatch Emergency and High Risk Operating States and Emergency Energy Outage Planning and Coordination Forced Outages and Forced Outage Requests Reliability Requirements... 19

25 Chapter 3 Reliable Operations CHAPTER 3 RELIABLE OPERATIONS 3.0 System Operator Roles and Responsibilities The System Operator (the SO ) is responsible for maintaining operational Reliability of the Integrated Electricity System (the IES ) In fulfilling its responsibility, the SO authorities include: a) Directing the operation to ensure the Reliability of the IES; b) Setting Reliability Requirements for the IES where such requirements do not contradict or diminish Board Approved Reliability Standards; c) Setting capacity requirements; d) Ensuring adequate Ancillary Services; e) Producing forecasts and assessments; f) Coordinating Outages of generation and transmission facilities; g) Entering into Operating Agreements with generators and loads; and h) Entering into Interconnection Agreements with owners and operators of transmission outside of New Brunswick Operating Agreements For the purpose of ensuring the safe and reliable operation of the IES or to supplement the operational requirements in Attachment J, Generation Connection Agreement, of the Open Access Transmission Tariff (the Tariff), the SO may require at any time a Transmission Customer with a Generation Facility connected to the IES to have and maintain an Operating Agreement with the SO For the purposes of ensuring the safe and reliable operation of the IES or to supplement the operational requirements in Attachment G, Network Operating Agreement, of the Tariff, the SO may require at any time a Transmission Customer Version: 01 Page 2

26 Chapter 3 Reliable Operations with a Load Facility connected to the IES to have and maintain an Operating Agreement with the SO SO Role as Reliability Coordinator and Balancing Authority outside New Brunswick Authority of the SO to function as the Reliability Coordinator outside New Brunswick is formalized through Interconnection Agreements with those system operators within the designated boundaries of the Reliability Coordinator footprint Authority of the SO to function as the Balancing Authority outside New Brunswick is formalized through Interconnection Agreements with those system operators within the designated boundaries of the Balancing Authority area The costs incurred by the SO in performing Reliability Coordinator and Balancing Authority functions outside of New Brunswick are allocated as defined in the respective Interconnection Agreements Reliability Based Requests from the System Operator Any party operating within the IES receiving a Reliability based request from the SO shall make all efforts to comply with such request and shall immediately notify the SO of any delays, or expected delays, and the reason for such delays in complying with the request. 3.1 Reliability Assessments Reliability Assessment Requirements The SO is responsible for power system Reliability Assessments and resource Adequacy Assessments, in accordance with the Reliability Standards, to ensure the IES is operated in a safe and reliable manner. This chapter provides a general Version: 01 Page 3

27 Chapter 3 Reliable Operations overview of the assessments carried out by the SO and shall not be interpreted as limiting any aspect of the assessments or data requirements Power System Reliability Assessments Power system Reliability Assessments shall, at a minimum, consist of: a) The results of resource Adequacy Assessments to ensure generation patterns, ancillary services and applicable constraints are considered as inputs to the power system Reliability Assessments; b) Seasonal assessments that will include all known Outages, constraints and system operating limits that are expected in the timeframe under review; c) Next day assessments that will ensure the IES will operate in a known studied state that will include known Outages, generation patterns and system operating limits for the next day; d) Current day assessments that will include changes in planned outages generation patterns and system operating limits; and e) Mitigation plans, as required, to ensure any potential limit violations identified in the above power system reliability assessments are addressed Resource Adequacy Assessments Resource Adequacy Assessments shall at a minimum consist of: a) A forecast of demand and Capacity Based Ancillary Services ( CBAS ) requirements for the NB Balancing Area. b) A determination of the capacity requirements of the NB Balancing Area. c) A determination of net generation margins for the NB Balancing Area which shall include: i. approved Outages and derations to Transmission and Generation Facilities, ii. a consideration for Forced Outage rates Version: 01 Page 4

28 Chapter 3 Reliable Operations iii. capacity located outside New Brunswick if the Transmission Provider determines such inclusion to be appropriate. iv. energy supply limitations of Generation Facilities including Non- Dispatchable Variable Generation Facilities. v. A determination of capacity resources required within a particular Zone or region in order to maintain Reliability within that zone or region Reliability Assessment Data Requirements To support Reliability Assessments, Transmission Users shall respond to data requests from the SO in the timeframes prescribed by the SO To support the timely assessments referred to in section (c), the Transmission Users as notified to submit such data under section , shall submit the necessary data to the SO by 11:00 a.m. Atlantic Time on the corresponding Day Ahead. 3.2 Ancillary Services Incremental Operating Reserve Where one or more transactions create exposure to a contingency in excess of the Incremental Operating Reserve Threshold, each Transmission User responsible for any such transaction shall self-supply its proportionate share of the Incremental Operating Reserve beyond the Incremental Operating Reserve Threshold required by the first or second contingency event, respectively In the event exposure to a first or second contingency in excess of the Incremental Operating Reserve Threshold arises the SO shall source Incremental Operating Reserve to account for any self-supply shortfall. The SO shall recover the costs Version: 01 Page 5

29 Chapter 3 Reliable Operations incurred in sourcing such Incremental Operating Reserve from each Transmission Customer responsible for the quantity that is not self-supplied Forecasting and Allocation of Capacity Based Ancillary Services Requirements for the Maritimes Area The SO shall enter into agreements with the operators of other transmission systems as may be required to give effect to, and to govern their respective rights and obligations as reflected in this section The SO shall prepare forecasts and determine the allocation for CBAS based on Reliability needs and shall consider arrangements with respect to neighbouring systems The SO shall prepare forecasts of requirements for CBAS for the Maritimes Area. In so doing, the SO shall separately identify any Operating Reserve requirement attributable to any Facility having a rated capacity of more than the Incremental Operating Reserve Threshold, as well as any transmission contingency in excess of the Incremental Operating Reserve Threshold On the basis of the forecasts prepared under section , but excluding any Operating Reserve requirement attributable to any Facility having a rated capacity of more than the Incremental Operating Reserve Threshold or to a source loss arising from a transmission contingency in excess of the Incremental Operating Reserve Threshold, the SO shall determine: a) First, the CBAS requirement to be fulfilled by the operator of the Transmission System in Nova Scotia, respecting applicable Reliability Standards, shall be in accordance with the provisions of the applicable agreement between the SO and that operator; and b) Frist, the load ratio share of the CBAS requirement to be fulfilled by each of the operators of the Transmission System in the province of Prince Edward Island and the operator of the Transmission System in northern Maine. Version: 01 Page 6

30 Chapter 3 Reliable Operations Such ratio shall be determined on the basis of the historical NCP billing data for each load over the previous calendar year and shall be used to determine each load s proportionate share of the NB Balancing Area CBAS requirement. Each January the load ratio share for each load will be calculated as a percentage obligation and provided by the SO and this percentage will apply for the 12-month period February to January, inclusive. The SO shall perform the allocation referred to in this section for each CBAS The SO shall prepare forecasts for Regulation and Load Following for Wind Power Generators and shall determine: a) Incremental Regulation and Load Following service requirements to address the aggregate impact of wind power generators in the NB Balancing Area. b) The ratio share, based on the net capacity of all wind power generators in the NB Balancing Area measured in MW, of the incremental Regulation and Load Following service produced by each of the operators of the wind power generators or the operators of the transmission to which the Facility is connected if the respective services are not being purchased under the Tariff The SO shall have authority to effect the activation of resources to provide CBAS in accordance with the agreements referred to in section Ancillary Services Self-Supply, Nomination, and Monthly Procurement Entities within the NB Balancing Area supplying CBAS shall satisfy the Ancillary Services Operational Requirements specified in Appendix E, in order to qualify for the supply of that particular service. Version: 01 Page 7

31 Chapter 3 Reliable Operations The Transmission Provider shall commit to provide Regulation, Load Following, and Operating Reserve capacity services for a given month based on the difference between the forecasted requirements for such services, and the total self-supply External Loads Facilities, who wish to self-supply an Ancillary Service may do so provided the agreements between system operators referenced in section define the nomination, activation and monitoring of such a service including the SO authority to effect the activation of the applicable service If a Transmission User self-supplies more than 100% of their monthly obligation, there is no credit. If a Transmission User self-supplies less than 100%, they are charged for the difference in accordance with the Tariff. The Ancillary Service charges for each Transmission User shall be determined each month by the SO. 3.3 Scheduling and Dispatch Scheduling and Dispatch Objectives The SO shall in sequence, with reliability being paramount: a) Economically commit and dispatch those resources owned by the Corporation or under contract to supply to the Corporation. b) To the extent that the commitments and dispatches of those resources are not sufficient to ensure Reliability of the IES or of any Zone, support the Supply of Emergency Energy or Security Energy, the SO shall utilize third party resources by committing, assigning them Must Run Status or Redispatching them Third Party Generator Re-dispatch/Must Run Compensation Respecting sections (Real Time Operation) and 3.4 (Emergency), for those instances where a Third Party Generator is assigned Must Run Status or is Redispatched, the Third Party Generator may choose to arrange an export transaction. Version: 01 Page 8

32 Chapter 3 Reliable Operations In absence of an export transaction the resource will be compensated according to section 4.8, based upon Dispatch Data submitted in section Third Party Generator Dispatch Data A Third Party Generation Facility shall submit, and update accordingly, cost estimates including start-up and minimum run costs for use by the SO in Re-dispatch or Must-Run of such Generating Facilities The SO may request additional supporting data and may review or audit data submitted under this section at any time within a year of the Re-dispatch event to which it applies. When requested, supporting data shall include fuel suppliers invoices for the cost of incremental fuel The Third Party Generation Facility shall promptly submit any additional data thus requested, and shall assist the SO in any review or audit If the SO determines that such additional data, review or audit reveals any Redispatch settlement to have been in error, it may following notice to the Third Party Generation Facility make appropriate settlement adjustments Generator Dispatch Data shall be submitted in the manner and form required by Appendix D Provisional Balanced Schedules A Balanced Schedule shall be submitted in the manner and form required by Appendix C and shall comply with the applicable requirements of this Chapter A Transmission User wishing to have the SO schedule an energy or Ancillary Service transaction on a Dispatch Day shall, except as otherwise noted in sections Version: 01 Page 9

33 Chapter 3 Reliable Operations and , by 11:00 a.m. Atlantic Time on the corresponding Day Ahead, submit to the SO a Provisional Balanced Schedule comprising of: a) A Balanced Schedule of energy flows utilizing Firm Point-to-Point Service, specifying injection Point of Receipt and withdrawal Delivery Points, including those at Interconnections, and the quantities of energy to be injected and withdrawn at each, to take account of transmission losses in accordance with the Tariff; b) A Balanced Schedule of energy flows utilizing Network Integration Service, specifying injection Points of Receipt and withdrawal Delivery Points or Virtual Delivery Points, including those at Interconnections where not prohibited by the Tariff, and the quantities of energy to be injected at each, taking account of transmission losses in accordance with the Tariff; and c) Schedules of self-supplied Ancillary Services A Transmission User shall by 1:00 p.m. Atlantic Time on the Day Ahead submit any new or revised updates to its Provisional Balanced Schedule if the need for such schedule updates could not have been known by the deadline noted in section Provisional Balanced Schedule, Assessment and Control Actions Based on the Provisional Balance Schedule submissions up to 1:00 p.m. Atlantic Time, the SO shall complete an assessment of the Provisional Balanced Schedules and reassess as necessary subsequent revisions for the purposes of ensuring the reliability of the IES or any Zones within The SO shall notify the Transmission User of issues identified in and the changes required that may include those actions described in section 3.4. Version: 01 Page 10

34 Chapter 3 Reliable Operations A Transmission User may, at any time prior to 3:00 p.m. Atlantic Time on the Day Ahead, update its Provisional Balanced Schedule for the corresponding Dispatch Day by submitting a new or revised Provisional Balanced Schedule, subject to continued compliance with any instruction issued under section Such updated Provisional Balanced Schedule if accepted by the SO shall supersede all earlier Provisional Balanced Schedules Generation Schedules Transmission Users submitting Balanced Schedules that include injections from Generation Facilities connected to the IES shall submit Generation Schedules that: Are consistent with the Generation Facilities' capabilities; Are consistent with the quantities included in the Transmission User s Balanced Schedules; Meet the same Tariff and Business Rules scheduling deadlines that apply to Balanced Schedules where any submissions beyond 1:00 p.m. Atlantic Time will require SO approval; Provide information as indicated in the following table for the Transmission User s generation scheduling mode as approved by the SO. The default mode is self-scheduling. SO approval for self-committing mode requires the Transmission User s submission of an unambiguous method by which the SO can assume or create a feasible generation dispatch plan. Generation Scheduling Mode Self-Committing Self-Scheduling Schedule Information Generation commitment in each interval ("1" for on and "0" for off) Average MW in each interval Version: 01 Page 11

35 Chapter 3 Reliable Operations Final Day Ahead Commitment Schedule Accepted Provisional Balanced Schedules, including those updated and accepted under section where applicable, shall become the Final Day Ahead Balanced Schedule (the FDABS ) In accordance with section , the SO shall, on the Day Ahead, optimize the dispatch for the 24 hours of the corresponding Dispatch Day in accordance with FDABS, updated Ancillary Service requirements, updated forecasts, scheduled exports, Third Party Generator Schedules, potential contingencies and the updated status of IES, including Outages and limits. On that basis, the SO shall prepare a Final Day Ahead Commitment Schedule ( FDACS ) The SO shall by 4:00 p.m., Atlantic Time on the Day Ahead make available to each Transmission User in respect of its own Generation Facilities its commitment schedule If a Transmission User becomes aware of any circumstance, excluding the normal production variability associated with Non-Dispatchable Variable Generators, that will or is likely to prevent that Transmission User from fulfilling its commitment schedule or any update thereto issued by the SO, it shall promptly notify the SO of the circumstances and of the likely consequences of such circumstances The Transmission User shall, working with the SO, promptly submit for the SO s acceptance revisions to its Balanced Schedule that address reliability concerns identified in section Hour Ahead Dispatch A Transmission User may submit a Balanced Schedule change request up to 30 minutes prior to the hour in accordance with the Tariff. The SO may reject any Version: 01 Page 12

36 Chapter 3 Reliable Operations Balanced Schedule change request that cannot be accommodated. The Balanced Schedule existing at 30 minutes prior to the start of the Dispatch Hour shall, subject to section , be the Final Hourly Balanced Schedule (the FHBS ) for that Dispatch Hour The SO may adjust a FHBS for settlement purposes to take account of: a) The failure of any Balanced Schedule to pass check-out with other system operators; b) The curtailment of any transaction underlying a Balanced Schedule as a result of transmission loading relief effected in accordance with NERC standards and practices; or c) The recall of any export or import transaction in accordance with the relevant provisions of the Balanced Schedule and Interconnection Agreements, including in respect of Operating Reserve and unit contingent import transactions, but not unit contingent export transactions recalled as a result of the associated unit contingency event A Transmission User for a Non-Dispatchable Variable Generator and similar facilities located in the NB Balancing Area must provide the SO with telemetry data via the SO SCADA system in respect of variable factors that affect production. This data may be used to adjust Balanced Schedules for Non-Dispatchable Variable Generators Final Hourly Commitment Schedule In accordance with section , the SO shall prepare a Final Hourly Commitment Schedule (FHCS) for the Dispatch Hour, together with an updated Commitment Schedule for up to three hours following the Dispatch Hour using updated load and Non-Dispatchable Variable Generators production forecasts, and the FHBS. Version: 01 Page 13

37 Chapter 3 Reliable Operations The SO shall use the FHCS as the basis for the Dispatch Instructions to be issued under section (d) During the hour prior to the start of each Dispatch Hour, the SO shall: a) Update its load forecasts, Non-Dispatchable Variable Generators production forecast and Ancillary Service Requirements; b) Update the status of the IES, including Outages and limits; c) Review Interconnection transactions, and confirm or deny approval in accordance with applicable Interconnection Agreements and the Reliability Standards; and d) No less than ten minutes prior to the start of the Dispatch Hour, issue required Dispatch Instructions to Transmission Users in respect of Generation Facilities Dispatch Instructions issued for Generation Facilities under section (d) may include: a) Instructions to operate at a given level of net power output; b) Instructions to ramp up or down at given rates over a given period or until reaching a given level of output; c) If the Generation Facility has an obligation to provide an Ancillary Service, instructions in accordance with the Facility s Generation Connection Agreement or Operating Agreement as may be required under Ancillary Services Operational Requirements specified in Appendix E; and d) In the case of Non-Dispatchable Variable Generators, Dispatch Instructions are not expected to be followed and will be equal to the lesser of the SO s forecast production or the Power Control Instruction The SO may also issue Dispatch Instructions at any time to operate the Generation Facility or an individual generation unit at a particular voltage level, power factor or level of reactive power output or absorption. Version: 01 Page 14

38 Chapter 3 Reliable Operations A Transmission User with a Generation Facility shall acknowledge receipt of its Dispatch Instructions and shall use its best efforts to operate its Generation Facilities in accordance with such Dispatch Instructions. The Generation Facilities shall operate within the tolerance band described in section or in accordance with the compliance requirements referred to in section , as applicable Dispatch Instructions continue in effect until superseded by later Dispatch Instructions In the event that a Transmission User with a Generation Facility does not receive a Dispatch Instruction at a time when it reasonably expects to receive such a Dispatch Instruction, it shall promptly contact the SO for clarification Sections , and do not apply to Non-Dispatchable Variable Generators. The SO may reduce dispatch of the facility via Power Control Instructions issued via the SO SCADA system With the exception of Non-Dispatchable Variable Generators the tolerance band for compliance with energy Dispatch Instructions shall be the greater of +/- 10 MW or 3% of (i) the dispatched output level in the case of a Generation Facility, or (ii) the load reduction in the case of Ancillary Service from a Load. Compliance within this band of energy Dispatch instructions does not relieve a Facility from applicable Energy Imbalance charges The requirements for the provision of an Ancillary Service shall be as set forth in the Ancillary Services Operational Requirements specified in Appendix E and in adherence with applicable Reliability Standards and Good Utility Practice If a Transmission User with a Generation Facility becomes aware of any circumstance that will or is likely to prevent that Transmission User with a Generation Facility from complying with its Dispatch Instructions the Transmission Version: 01 Page 15

39 Chapter 3 Reliable Operations User with a Generation Facility shall promptly notify the SO of the reasons for the inability to comply and of the consequences of such inability Real Time Operation Using real time information, forecasts and anticipated schedules the SO shall initiate such control actions as may be required to maintain Reliability of the IES and of any Zone including those actions described in section On a continuous basis the SO shall issue Power Control Instructions in respect of the output settings to Non-Dispatchable Variable Generators via the SO s SCADA system. The Power Control Instruction would normally be set at the maximum output of the Facility Activation of reserve will be performed with emphasis on reliability and at the SO s discretion. All else being equal, the SO will activate the required reserve from all suppliers providing the service on a pro rata basis in proportion to the respective supply. 3.4 Emergency and High Risk Operating States and Emergency Energy The SO shall develop and have accessible to Transmission Users, procedures to be applied in the following circumstances: a) Where the SO identifies an actual or forecast shortage in the supply of energy or the provision of Ancillary Services other than Black Start Capability Service; b) Where the SO identifies an actual or forecast surplus energy supply; and c) Where the SO identifies or anticipates an increase in the risk of the occurrence of contingency events within the IES or in an electricity system that is interconnected with the IES, or an increase in the consequences of a contingency event that may occur. Version: 01 Page 16

40 Chapter 3 Reliable Operations Where the SO receives a request for the provision of Emergency Energy under and in accordance with an Interconnection Agreement, it shall provide such Emergency Energy to the requesting party subject to the terms of the Interconnection Agreement. 3.5 Outage Planning and Coordination Planned Outage requests shall be made no later than 11:00 a.m. Atlantic Time two business days before the Outage is scheduled to begin to the extent possible, however, planned Outage requests made later shall be considered if practicable. To avoid scheduling conflicts, it is recommended the party use its best efforts to submit Outage requests to the SO at the earliest opportunity The requesting party of a planned Outage that has already been submitted for approval shall notify the SO as soon as possible of any required changes No Outage request shall be approved until it has been assessed by the SO The SO shall make best efforts to assess all known Outages and their impact on system Reliability as soon as practical. All known Outage requests shall be accordingly assessed in the seasonal or planning horizon, next-day and current day timeframes In performing Outage coordination activities the SO shall minimize, as much as practicable, any disruption to the operations of Transmission Users. The SO shall use best efforts to coordinate all Outages to minimize as much as practicable the economic, safety and reliability impacts of the Outages. Version: 01 Page 17

41 Chapter 3 Reliable Operations Outage Approvals, Rejections and Retractions Where Outage requests pose unacceptable risk to safety or Reliability, and such risks cannot be reasonably mitigated, the requests shall be denied by the SO Where there is a conflict between two or more Outage requests, the SO will work in consultation with the parties to reach a solution. Where a solution cannot be found, Outage priority will be determined based on the Outage submission request dates In cases where an Outage request was approved by the SO and conditions within the IES have changed such that the outage will pose a risk to safety or system Reliability, the SO shall retract the approval of the Outage and the work shall not begin until such time it is deemed acceptable by the SO In cases where an Outage request was approved by the SO and work has already begun, should the conditions of the IES change such that the Outage will pose an unacceptable risk to safety or system Reliability, the SO shall notify the affected parties. The affected parties shall make best efforts to restore the system to the configuration as determined by the SO and the Outage approval shall be considered retracted and no longer in force or effect. If the affected parties cannot restore the system to the configuration as directed by the SO in an acceptable timeframe, the SO shall take control actions to ensure the IES is operated in a safe and reliable manner The SO shall develop and have accessible to Transmission Users an operating procedure further describing Outage planning and coordination activities. Version: 01 Page 18

42 Chapter 3 Reliable Operations 3.6 Forced Outages and Forced Outage Requests A Transmission User may take whatever reasonable action it deems necessary for reasons of safety, to protect its equipment from immediate material harm or to prevent serious environmental damage arising from unforeseeable events Transmission Users that require an immediate Forced Outage shall inform the SO as soon as practicable as to the reason for the Forced Outage and the expected duration of the Forced Outage. The Transmission User shall give the SO timely updates, throughout the Forced Outage, as to the Outage status and return to service time Transmission Users that foresee a need for a Forced Outage shall inform the SO of such need and request approval for the equipment to be taken out of service. If requested by the SO for Reliability reasons, the requesting party shall make all practical efforts to keep the equipment in service and postpone the Outage. 3.7 Reliability Requirements The Transmission Provider in ensuring the reliable planning, design and operation of the IES may set Reliability Requirements. Reliability Requirements will be applicable, on a non-discriminatory basis, to those parties that are material to the Reliability of the IES Appendix F, lists Northeast Power Coordinating Council ( NPCC ) criteria and directories established by the Transmission Provider to be Reliability Requirements necessary for the reliability of the IES. The Transmission Provider may adopt or develop additional Reliability Requirements which may not be limited to those of NPCC. Appendix F will be updated with any such additions or modifications. Version: 01 Page 19

43 Chapter 3 Reliable Operations Based on Appendix F, the Transmission Provider will notify Transmission Users of any Reliability Requirements applicable to the Transmission User and their obligations to ensure satisfactory compliance with the requirements. Version: 01 Page 20

44 New Brunswick Electricity Business Rules Chapter 4 Billing and Payment

45 Chapter 4 Billing and Payment TABLE OF CONTENTS CHAPTER 4 BILLING AND PAYMENT Billing and Payment Metering Data Management Timing of Billing and Payment Billing in Accordance with the Tariff Allocation of Tariff Revenues to Transmitters Payments to Third Party Suppliers of Reactive Supply and Voltage Control Provision of Capacity-Based Ancillary Services Payments for Third Party Generation Facility Re-dispatch Energy Credits to the Corporation for Net Re-dispatch Energy Imbalance (Variance) and Schedule Rounding Amounts Ancillary Services Re-dispatch and Congestion Management Costs Residual Uplift Final Hourly Marginal Cost Version: 01 Page 1

46 Chapter 4 Billing and Payment CHAPTER 4 BILLING AND PAYMENT 4.1 Billing and Payment Billing of, and payment to, Transmission Users shall be performed in accordance with the Open Access Transmission Tariff (the Tariff ). Additional details provided within these Electricity Business Rules (the Business Rules ) are intended to provide clarity and more specificity The System Operator (the SO ) shall perform settlement calculations and prepare settlement statements for all Transmission Users. Settlement within the Corporation, including transactions with the SO will not be subject to invoicing and payment, but will be recorded as book entries only. Settlement between the SO and the Corporation's Affiliates will be subject to invoicing and payment. 4.2 Metering Data Management Transmitters shall provide to the SO, or make available for automated transfer, metering data in accordance with the requirements of the Tariff and the Business Rules in accordance with the billing and payment timing identified herein Metering data is the confidential property of the SO Metering data, including meter output data and all error corrections and adjustments, shall be made available in a reasonable and convenient form to the SO and to any Transmission User whose settlement under the Tariff or the Business Rules is directly dependent on such metering data. Version: 01 Page 2

47 Chapter 4 Billing and Payment 4.3 Timing of Billing and Payment The process of billing and payment under the Tariff shall be performed in accordance with the timeline that is contained in the following table. The timing is defined in terms of Business Days following the month in which the billing and payment obligations were incurred. Table A Timing of Billing and Payment Deadline Responsible Entity Activity End of First Business Day Transmitters Make metering data available to the SO including with respect to load transfers. End of Fourth Business Day Noon of Fifth Business Day End of Fifth Business Day SO Transmitter and Transmission Users SO Process metering data (e.g. adjust, review, correct, estimate, and aggregate as required). Calculate and issue preliminary charges and payments to payers and payees. Review relevant preliminary charges and payments. Alert SO of suspected errors in the posted charges and payments. Make required corrections to charges and payments calculations and reissue. Issue invoices. As per Tariff Transmission Users Make Tariff payments as per the Tariff and invoices. As per the applicable contract SO Make payments for services provided in accordance with relevant contracts. 4.4 Billing in Accordance with the Tariff Billing for services under the Tariff shall be performed in accordance with the Tariff, subject to additional clarification or details as specified herein. Version: 01 Page 3

48 Chapter 4 Billing and Payment 4.5 Allocation of Tariff Revenues to Transmitters The SO shall allocate revenue received from Transmission Customers as payment for use of the transmission system to Transmitters in proportion to their respective revenue requirements as approved by the Board The SO shall allocate revenue received from Transmission Customers as payment for power factor penalties in accordance with the Tariff to the Transmitter that owns the transmission system to which the Facility incurring the power factor penalty is connected. 4.6 Payments to Third Party Suppliers of Reactive Supply and Voltage Control Payments to suppliers of Reactive Supply and Voltage Control capability by the SO will be made in accordance with contracts. The following principles apply to any new or revised contracts for the provision of Reactive Supply and Voltage Control from Facilities that are not owned by the Corporation. All Facilities shall provide the service in accordance with Attachment J of the Tariff, the Generation Connection Agreement, and Appendix E of the Business Rules, Ancillary Services Operational Requirements ; All Facilities providing the service shall be eligible for compensation provided that a contract is in effect; Compensation shall be on the basis that all new providers are compensated equally for the same service; The SO shall not compensate more than one party for provision of the same service over the same period of time from the same Facility. The SO shall have no obligation to establish or maintain additional compensation to the owner or operator of a Facility for provision of the service should a compensation arrangement with the owner or operator already be in place for the service from the Facility; and Version: 01 Page 4

49 Chapter 4 Billing and Payment To the extent feasible, compensation by the SO to the owner or operator of a Facility shall be consistent with the unit price and provision metric inherent in the cost of service study for the most recently approved Tariff charges for Reactive Supply and Voltage Control service The SO shall credit to the Corporation the full amounts collected for services under the Tariff for Reactive Supply and Voltage Control capability, less the compensation paid by the SO to suppliers of Reactive Supply and Voltage Control from Facilities not owned by the Corporation. 4.7 Provision of Capacity-Based Ancillary Services Given that the Corporation is the exclusive provider of Capacity-Based Ancillary Services with respect to requirements that are not met through SO approved Transmission Customer arranged services (i.e. Transmission Customer self-supply or Transmission Customer arranged supply by another party), the SO does not pay Third Party suppliers for provision of Capacity-Based Ancillary Services. Similarly, the SO does not use these services of Third Party suppliers other than with respect to SO approved Transmission Customer arranged services or emergency conditions In the case of a Transmission Customer s self-supply of Capacity Based Ancillary Services, compensation for energy produced upon activation will be the same as for imbalance. 4.8 Payments for Third Party Generation Facility Re-dispatch Energy The SO will pay/charge owners of Third Party Generation Facilities for energy Redispatch based on their incremental costs, which may include start-up and minimum run costs, and energy costs. Opportunity costs can be included upon request of the owner of the Third Party Generation Facility. Payment or charge for any such Version: 01 Page 5

50 Chapter 4 Billing and Payment opportunity costs will be subjected to an audit at the SO's discretion by an independent reviewer selected by the SO and the owner. Should the audit indicate that the opportunity costs are unsubstantiated the owner shall reimburse the SO for the cost of audit and the payment/charge for the Re-dispatch shall be corrected The quantity of eligible Re-dispatch of a Third Party Facility in any hour in MWh is the difference between the Dispatch Instruction and the scheduled output from a given Third Party Facility indicated by all Balanced Schedules The quantity of eligible Third Party Re-dispatch energy will be positive if the Dispatch Instruction is greater than the scheduled output indicated by all Balanced Schedules, and negative if the Dispatch Instruction is less than the scheduled output indicated by all Balanced Schedules The charge (in the case of negative Re-dispatch), or credit (in the case of positive Redispatch), to a third-party that has been subject to Re-dispatch shall be equal to the quantity of eligible third-party Re-dispatch energy multiplied by the customer s previously submitted expected variable fuel and operation and maintenance cost per MWh of compliance with the Re-dispatch instruction, or in the case that a submission of actual costs has been made within the first 3 Business Days following the calendar month in which the Re-dispatch occurred, the customer s post-dispatch submission of actual variable fuel and operation and maintenance cost per MWh of compliance with the Re-dispatch instruction, which may include reference to previously filed cost information and must not differ from the expected value by any more than +/-20% Section 4.8 is not applicable in those occasions where a Third Party Generation Facility included in an Ancillary Service self-supply schedule is dispatched by the SO to activate CBAS where said dispatch results in an injection of energy to the IES. Any additional energy generated by Third Party Generation Facilities as a result of activation for CBAS will be treated as Energy Variance as described in section Version: 01 Page 6

51 Chapter 4 Billing and Payment 4.9 Credits to the Corporation for Net Re-dispatch The Corporation fulfills all Energy Imbalance requirements except those fulfilled by re-dispatch of other third Party Generation Facilities The SO shall credit or charge the full amounts collected for services under the Tariff that are inherently provided using Re-dispatch energy (e.g. energy imbalance, ancillary services out-of-order dispatch, congestion management, schedule rounding amounts) to the Corporation, less the net amount of settlement with other Third Party Generation Facilities Re-dispatch Energy Imbalance (Variance) and Schedule Rounding Amounts The SO shall determine Settlement Amounts for actual energy imbalances (variances) and associated costs as follows: a) The SO shall determine, on the basis of metering data, for each Generation Facility for each hour the Imbalance Quantity - Generation (IQG), which shall be the quantity of any actual variance in the output of energy by that Generation Facility relative to its Dispatch Instructions; b) The SO shall charge or credit each Generation Facility that has an IQG in a given hour at the FHMC; c) The SO shall determine, on the basis of metering data, for each Load Facility or corresponding Virtual Delivery Point for each hour the Imbalance Quantity - Load (IQL), which shall be the difference between the actual or imputed hourly metering data for that Load Facility or Virtual Delivery Point and the energy quantity in the Final Hourly Balanced Schedule or FHBS; d) The SO shall charge or credit each Load Facility that has an IQL in a given hour at the price indicated by the Tariff for that hour at the FHMC, multiplied by the applicable loss factor specified in the Tariff; and Version: 01 Page 7

52 Chapter 4 Billing and Payment e) Variances in the import or export flows on Radial Interconnections shall, after accounting for inadvertent flows in accordance with the provisions of applicable Interconnection Agreements, be treated in the same manner as variances in respect of Generation Facilities and Load Facilities, respectively The SO shall determine the schedule rounding error for each hour in accordance with the following formula: Q(injection) [Q(withdrawal) * (1 + transmission loss factor)] rounded to the nearest kwh The SO shall determine the Schedule Rounding Amount (SRA) due in each hour to each Transmission Customer as the schedule rounding error determined in accordance with this section multiplied by FHMC for each of the Transmission Customer s Balanced Schedules The net amount payable to a Facility under section (b) or (d) shall be the Actual Energy Variance Settlement Credit or AEVSC (or AEVSCG for Generation Facilities and AEVSCL for Load Facilities) Ancillary Services Re-dispatch and Congestion Management Costs The SO shall determine the Day Ahead energy Re-dispatch costs as follows: a) The SO shall determine an optimized Day Ahead, energy only unconstrained Commitment Schedule, referred to as DAEOUS, using data identical to that used in determining the Final Day Ahead Commitment Schedule except that CBAS dispatch requirements are reduced by any CBAS obligations for Load Facilities (including External Load Facilities), Incremental Operating Version: 01 Page 8

53 Chapter 4 Billing and Payment Reserve and Wind facilities, and all Transmission constraints within the Province shall be ignored; b) The SO shall determine an optimized Day Ahead, energy and Ancillary Services unconstrained Commitment Schedule, referred to as DAEAUS, using data identical to that used in determining the Final Day Ahead Commitment Schedule except that all Transmission constraints within the Province shall be ignored; c) The SO shall determine an optimized Day Ahead, energy and Ancillary Services unconstrained Commitment Schedule with the Incremental Operating Reserve obligations removed, referred to as DAEAUS*, using data identical to that used in determining the Final Day Ahead Commitment Schedule except that all Transmission constraints within the Province shall be ignored and CBAS dispatch requirements are reduced by the total Incremental Operating Reserve obligation; d) The SO shall determine an optimized Day Ahead, energy and Ancillary Services unconstrained Commitment Schedule with CBAS for Wind requirements removed, referred to as DAEAUS~, using data identical to that used in determining the Final Day Ahead Commitment Schedule except that all Transmission constraints within the Province shall be ignored and Ancillary Service dispatch requirements are reduced by the total Incremental Operating Reserve obligation and by the total CBAS for Wind obligation; e) The SO shall calculate the total generation cost, consisting of start-up costs, minimum run costs and incremental energy costs above minimum run quantity, for each corresponding Dispatch Day associated with each of the following Commitment Schedules: i. The DAEOUS, for which the cost shall be designated as DAEOUC ii. The DAEAUS, for which the cost shall be designated as DAEAUC iii. The DAEAUS*, for which the cost shall be designated as DAEAUC* Version: 01 Page 9

54 Chapter 4 Billing and Payment iv. The DAEAUS~, for which the cost shall be designated as DAEAUC~ v. The Final Day Ahead Commitment Schedule, for which the cost shall be designated as FDACC f) The SO shall calculate the total Ancillary Service Re-dispatch Cost (ASRC), which shall be DAEAUC minus DAEOUC; g) The SO shall calculate the total Ancillary Service Re-dispatch Cost attributed to Incremental Operating Reserves (ASRC*), which shall be DAEAUC minus DAEAUC*; h) The SO shall calculate the total Ancillary Service Re-dispatch Cost attributed to Wind Facilities (ASRC~), which shall be DAEAUC* minus DAEAUC~ i) The SO shall calculate the total Congestion Management Cost (CMC), which shall be FDACC minus DAEAUC; and j) Where the Final Day Ahead Balanced Schedule schedules a Generation Facility to have a total output that is not zero and lies outside the possible range as known by the SO, then the values of each of DAEOUC, DAEAUC*, DAEAUC~, DAEAUC and FDACC shall be calculated on the basis that such Schedule requires the Generation Facility to be operating and using a redispatch price of zero for all energy outside of the possible operating range The SO will calculate that portion of Ancillary Service Re-dispatch costs to be attributed to all Load Facilities (including External Load Facilities) having a CBAS obligation under the Tariff as the total Re-dispatch cost (ASRC) less that portion attributed to Incremental Operating Reserve (ASRC*) and that portion attributed to Wind (ASRC~) The SO shall allocate the portion of ASRC attributed to Load Facilities (including External Load Facilities) to individual Ancillary Services as follows: Version: 01 Page 10

55 Chapter 4 Billing and Payment a) The SO shall determine the total quantity, in MWh, of each Ancillary Service scheduled in the FDACS to be provided on the corresponding Dispatch Day and shall determine the equivalent quantity of Load Following Service for each such Ancillary Service as follows: i. Each MWh of Automatic Generation Control Service (AGC) shall be deemed to be equivalent to 1.25 MWh of Load Following Service; ii. Each MWh of 10-minute spinning Operating Reserve Service shall be deemed to be equivalent to 0.75 MWh of Load Following Service; iii. Each MWh of 10-minute non-spinning Operating Reserve Service shall be deemed to be equivalent to 0.50 MWh of Load Following Service; and iv. Each MWh of 30-minute Operating Reserve Service shall be deemed to be equivalent to 0.40 MWh of Load Following Service; b) The SO shall determine the ASRC for each MWh of equivalent Load Following Service and shall allocate the ASRC accordingly to each class of Ancillary Service for the Dispatch Day; and c) The SO shall thus determine the total for each Settlement Period of the redispatch costs that are attributed to Load Facilities (including External Load Facilities) associated with each Ancillary Service The SO shall determine the Ancillary Service re-dispatch Settlement Amounts to be debited to each Load having a CBAS obligation in respect of each of AGC, Load Following Service and all three classes of Operating Reserve Service. The debits are calculated as follows: i. The rate per MWh for each type of Ancillary Service is calculated as the portion of ASRC for Load Facilities (including External Load Facilities) attributed to that Ancillary Service type in above Version: 01 Page 11

56 Chapter 4 Billing and Payment divided by the total MWh obligation for all Load Facilities (including External Load Facilities) for that Ancillary Service type ii. The debit for each Load Facility (including External Load Facilities) and Ancillary Service type is then calculated as the obligation MWh for that Load Facility (including External Load Facilities) and Ancillary Service type that was not self-supplied, multiplied by the rate per MWh for that type of Ancillary Service determined above in (i) The SO shall allocate the Incremental Reserve Re-dispatch cost (ASRC*) amongst the Transmission Customers responsible for the transactions that triggered the incremental Operating Reserve requirement as a debit in proportion to each such Transmission Customer s contribution to the total requirement of each class of Operating Reserve after accounting for any SO approved self-supply arrangements made by each Transmission Customer Residual Uplift Residual Uplift is deemed to be zero Final Hourly Marginal Cost The FHMC is the marginal cost saving to the system that would have been achieved if system primary demand had been reduced by 1 MW. Version: 01 Page 12

57 ELECTRICITY BUSINESS RULES Appendix A Definitions

58 Appendix A - Definitions Term Definition 10-Year Outlook Has the meaning given in section Actual Energy Variance Settlement Credit (AEVSC) Actual Energy Variance Settlement Credit for Generation (AEVSCG) Actual Energy Variance Settlement Credit for Load (AEVSCL) Adequacy Adequacy Assessments Ancillary Service(s) Ancillary Services Re-Dispatch Cost (ASRC) Automatic Generation Control Service (AGC) Available Transfer Capability (ATC) Balanced Schedule Has the meaning given to it in section 4.10 Has the meaning given to it in section 4.10 Has the meaning given to it in section The ability of a Zone, a Transmission System or the Integrated Electricity System to supply aggregate electrical Demand and energy requirements to some recognized degree of certainty at all times, taking into account scheduled and reasonably unscheduled Outages of facilities, equipment or components. The ability of supply-side and demand-side resources to meet the aggregate electrical demand (including losses). As defined in the Tariff [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]. Has the meaning given to it in section 4.11 An Ancillary Service under which the output from a Generation Facility is automatically adjusted by the SO from a centralized location based on automated, electronic signals in order to control frequency and to maintain the short-term balance of load and generation. The transfer capability remaining in the Transmission System for further commercial activity over and above already committed uses. A schedule submitted to the SO by a Transmission Customer for the purpose of requesting the SO to schedule an Ancillary Services self-supply or energy transaction into, through or out of the Integrated Electricity System. Version: 01 Page 1

59 Appendix A - Definitions Balancing Authority Baseline Plan As defined in the NERC Glossary of terms. [The responsible entity that integrates resource plans ahead of time, maintains load-interchange-generation balance within a Balancing Authority Area, and supports Interconnection frequency in real time]. A plan prepared by the SO in accordance with Chapter 2 of the Electricity Business Rules. Black Start Capability Service Board Board Approved Reliability Standards Business Day Capacity Based Ancillary Services (CBAS) Commitment Schedule Connection Applicant Connection Assessment Corporation Day Ahead Delivery Point An Ancillary Service which is the capability of a Generation Facility or generation unit to go from a shutdown condition to an operating condition and to start delivering energy without the assistance of an outside electrical supply.. As defined in the Electricity Act. [The New Brunswick Energy and Utilities Board continued under Energy and Utilities Board Act]. Reliability standards that have been approved by the New Brunswick Energy and Utilities Board. As defined in the Tariff. [A Business Day is Monday to Friday, inclusive, excluding statutory holidays for the Transmission Provider. The regular business hours on a Business Day are from 08:15 hour to 16:30 hour Atlantic Time]. The ancillary services outlined in Schedules 3, 5 and 6 of the Tariff. A schedule prepared by the SO that identifies the required start-up, synchronization and operation of Facilities. A person that applies to the SO for approval of the connection of a new or modified facility to the IES or for approval to make or modify an Interconnection. A Feasibility Review and/or a System Impact Study, as the context may require. Means NB Power. The Business Day immediately preceding the Dispatch Day. A point of connection on the IES where energy and capacity are injected or withdrawn. Version: 01 Page 2

60 Appendix A - Definitions Dispatch Data Dispatch Day Dispatch Hour Dispatch Instructions Distribution System Electricity Act Electricity Business Rules (the Business Rules ) Emergency Energy External Load Facility Facility (Facilities) Feasibility Review Final Day Ahead Balanced Schedule (FDABS) Data submitted to the SO by a Transmission User for a Generation Facility for use by the SO in the scheduling and dispatch of the IES and certain Facilities and in the settlement in respect of re-dispatch. A day on which the SO schedules and dispatches Facilities. An hour for which a schedule or Dispatch Instructions are issued by the SO. Instructions issued by the SO under 3.3 in respect of a Facility that direct the manner in which the Facility must operate during a Dispatch Hour. A system for distributing electricity to consumers at voltages of less than 69 kv, and includes any structures, equipment or other things used for that purpose. The New Brunswick Electricity Act. The Electricity Business Rules established under section 74 of the Electricity Act. Energy acquired by the SO from another Balancing Authority or the operator of a transmission system in a neighbouring jurisdiction or provided by the SO to another Balancing Authority or to the operator of a transmission system in a neighbouring jurisdiction to maintain either the Reliability of the IES or the Reliability of a transmission system in a neighbouring jurisdiction. A load facility outside New Brunswick but within the NB Balancing Area. A Load Facility, a Generation Facility, and/or a Transmission Facility as the context may require and, except as otherwise provided in the Business Rules. A review conducted by the Transmission Provider under the Business Rules Chapter 2. A Balanced Schedule described in section Version: 01 Page 3

61 Appendix A - Definitions Final Day Ahead Commitment Schedule (FDACS) Final Hourly Balanced Schedule(FHBS) Final Hourly Commitment Schedule (FHCS) Final Hourly Marginal Cost (FHMC) Forced Outage Firm ATC Firm Point-to-Point Transmission Service Generation Connection Agreement Generation Facility Generation Schedule Good Utility Practice A Commitment Schedule prepared by the SO under section A Balanced Schedule described in section A Commitment Schedule prepared by the SO under section The marginal cost saving to the system that would have been achieved if system primary demand had been reduced by 1 MW in the FHCS referred to in section The removal from service of equipment for emergency reasons or a condition in which the facility equipment is unavailable, in whole or in part, due to unanticipated failure, and includes a forced de-rating. For greater certainty, the urgent removal from service or de-rating of equipment in order to prevent an actual failure that could jeopardize safety, the environment, or the equipment itself may, if it could not reasonably have been anticipated, be considered a Forced Outage. Has the meaning given to it in the Tariff. Has the meaning given to it in the Tariff. An agreement between the Transmission Provider and a generator owner, as described in Attachment J of the Tariff. As defined in the Electricity Act [a Facility for generating electricity or providing Ancillary Services, other than Ancillary Services provided through the operation of a Transmission System, and includes any structures, equipment or other things used for that purpose]. A schedule indicating a Transmission User s intentions with respect to production of each of its Generation Facilities in each time interval covered by the schedule. As defined in the Tariff. [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 Version: 01 Page 4

62 Appendix A - Definitions Imbalance Quantity Generation (IQG) Imbalance Quantity Load (IQL) Incremental Operating Reserve Incremental Operating Reserve Threshold 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.] Has the meaning given to it in section 4.10 Has the meaning given to it in section 4.10 Operating reserve requirements arising from contingencies in excess of the Incremental Operating Reserve Threshold. The threshold contingency size referred to in Schedules 5 and 6 of the Tariff. Effective Date Value (MW) October 1, July 1, Integrated Electricity System (IES) Interchange Transaction Tag (e-tag) Interconnection Interconnection Agreement Load Facility As defined in the Electricity Act [The transmission systems in the Province and the structures, equipment or other things that connect those transmission systems with generation facilities and distribution systems in the Province and with transmission systems outside the Province] The details of an Interchange Transaction required for its physical implementation. A connection between the IES and a Transmission System outside of New Brunswick. An agreement between the SO and the person that owns or operates a Transmission System outside of New Brunswick with respect to the operation of an Interconnection with the IES. A Facility that draws electricity from the IES and includes any structures, equipment or other things used for that purpose. Version: 01 Page 5

63 Appendix A - Definitions Load Following Service Long-Term Firm Maritimes Area Must-Run Status NB Balancing Area NERC Network Integration Transmission Service Network Operating Agreement Network Secondary Non-Dispatchable Variable Generators North America Energy Standards Board (NAESB) Northeast Power Coordinating Council (NPCC) Has the meaning given to it in the Tariff. Has the meaning given to it in the Tariff. The area comprising the Province of New Brunswick, the Province of Nova Scotia, the Province of Prince Edward Island and two areas within the northern part of the State of Maine. A generation resource is assigned a must-run status when the absence of the generation resource will result in an unacceptable reliability risk or have adverse impact on the Integrated Electricity System or Zones within. The combined areas of New Brunswick, Prince Edward Island and Northern Maine, as defined by those Interconnection agreements referenced in section Means the North American Electric Reliability Corporation. As defined in the Tariff. As defined in the Tariff. [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]. Has the meaning given to it in the Tariff. A generation facility that is subject to instantaneous or nearinstantaneous limitation on its output by wind speed, river flows, or other non-controllable variable inputs. The North American Energy Standards Board (NAESB) serves as an industry forum for the development and promotion of standards which will lead to a seamless marketplace for wholesale and retail natural gas and electricity, as recognized by its customers, business community, participants, and regulatory entities. A not-for-profit corporation in the state of New York responsible for promoting and improving the reliability of the international, interconnected bulk power system in North Eastern North America. NPCC geographic region is comprised of the State of New York and the six New England states as Version: 01 Page 6

64 Appendix A - Definitions well as the Canadian provinces of Ontario, Québec and the Maritime provinces of New Brunswick and Nova Scotia. NPCC is one of the eight Regional Reliability Organizations within NERC. OASIS As defined in the Tariff. Open Access Transmission Tariff (the Tariff ) Has the same meaning as approved transmission tariff as defined in the Electricity Act. Operating Agreement An agreement between the SO and a Generation, Transmission, or Load Facility owner that details operating procedures and practices necessary for the safe and reliable operation of the IES. Operating Reserve Operating Reserve Service Outage(s) Point(s) of Delivery (POD) Point(s) of Receipt (POR) Point-To-Point Transmission Service Generation capacity or load reduction capacity that can be called upon on short notice by the SO to replace scheduled energy supply which is unavailable as a result of an unexpected Outage or to augment scheduled energy as a result of unexpected Demand or other contingencies. An Ancillary Service under which generation capacity or load reduction capacity can be called upon on short notice by the SO to replace scheduled energy supply which is unavailable as a result of an unexpected Outage or to augment scheduled energy as a result of unexpected Demand or other contingencies. Refers to any transmission equipment Outage or de-rate, generation Outage or de-rate, facility Outage or de-rate, protection equipment or scheme Outage, Supervisory Control And Data Acquisition (SCADA) component or system Outage or any other Outage to equipment or schemes deemed by the System Operator to be impactive to the power system or any combination thereof. As defined in the Tariff. As defined in the Tariff. As defined in the Tariff. [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]. Version: 01 Page 7

65 Appendix A - Definitions Point-to-Point Transmission Service Agreement An agreement entered into by the Transmission Customer and the Transmission Provider for Point-to-Point Transmission Service, with such service as defined in the Tariff. Power Control Instruction Has the meaning given to it in section Provisional Balanced Schedule A Balanced Schedule that has not yet become a Final Day Ahead Balanced Schedule. Proximate Area Published Purchasing-Selling-Entity (PSE) Radial Interconnection(s) Reactive Supply and Voltage Control Re-dispatch Regional Reliability Organization Regulation Reliability Reliability Assessments An area on the IES that is electrically proximate to the IES that is the subject-matter of a Request for Connection Assessment. Means posted on NB Power s external website or Open Access Same-Time Information System or otherwise simultaneously available to all Transmission Users and potential Transmission Users. The entity that purchases or sells, and takes title to, energy, capacity, and Interconnected Operations Services. Purchasing-Selling Entities may be affiliated or unaffiliated merchants and may or may not own generating facilities. An Interconnection with a Transmission System whose only point of connection with another jurisdiction is with the IES. An Ancillary Service under which a Generation Facility adjusts its output to maintain reactive power levels and the voltage required by the IES. Adjustment by the SO of a generation facility s MW output schedule from that provided by the Transmission User. Refer to Northeast Power Coordinating Council (NPCC). Has the meaning given to it in the Tariff. The degree of performance of a Zone, a Transmission System, or the Integrated Electricity System that results in electricity being delivered within accepted standards in an Adequate and secure manner and in the amount desired. Assessments carried out on an operational or planning horizon to ensure the reliability of the Integrated Electricity System and interconnected systems. Version: 01 Page 8

66 Appendix A - Definitions Reliability Coordinator Reliability Directive Reliability Requirements As defined by NERC. [The entity that is the highest level of authority who is responsible for the reliable operation of the Bulk Electric System, has the Wide Area view of the Bulk Electric System, and has the operating tools, processes and procedures, including the authority to prevent or mitigate emergency operating situations in both next-day analysis and real-time operations. The Reliability Coordinator has the purview that is broad enough to enable the calculation of Interconnection Reliability Operating Limits, which may be based on the operating parameters of transmission systems beyond any Transmission Operator s vision. As defined by NERC. [A communication initiated by a Reliability Coordinator, Transmission Operator, or Balancing Authority where action by the recipient is necessary to address an Emergency or Adverse Reliability Impact. Reliability Standards developed or adopted by the Transmission Provider as described in section 3.7. Reliability Standards Board Approved Reliability Standards or Transmission Provider Reliability Requirements. Request for Connection Assessment A request submitted to the SO under section 2.2 for the purpose of obtaining the SO s approval for the connection of a new or modified Facility to the IES or the SO s approval to make or modify an Interconnection Residual Uplift Has the meaning given to it in section Supervisory Control and Data Acquisition (SCADA) Schedule Rounding Amount (SRA) Settlement Period The real-time operating system used by the SO to monitor and control the Integrated Electricity System The amount determined under section A period of one month for which settlement amounts are calculated and settlement statements are issued. Short Term Firm Point-to- As defined in the Tariff. Point Transmission Service Standards of Conduct Board approved compliance program describing the separation of marketing and transmission functions to ensure no undue preferential treatment of the Corporation s affiliate marketing division. Version: 01 Page 9

67 Appendix A - Definitions System Impact Study System Operator (SO) Third Party Transmission Customer Transmission Function Transmission Provider Transmission Service As defied in the Tariff. [An assessment by the Transmission Provider of the adequacy of the Transmission System to accommodate a request for either Firm Point-To-Point Transmission Service or Network Integration Transmission Service and whether any additional costs may be incurred in order to provide transmission service]. A subset of the Transmission Provider that performs Transmission Functions. Ownership other than by the Corporation. As defined in the Tariff. [Any Eligible Customer (or its Designated Agent) that executes a Service Agreement, or requests in writing that the Transmission Provider file with the Board, 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 and Part III of this Tariff]. As defined in NB Power s Standards of Conduct. [involves the planning, directing, organizing or carrying out of day-to-day transmission operations, including the granting and denying of transmission service requests. The transmission function includes activities focused on short-term real time operations, including those decisions made in advance of real time but directed at real time operations, and activities that support the granting or denying of requests for transmission service including interconnection service]. As defined in the Tariff. [New Brunswick System Operator or its successor (or its Designated Agent) that controls and directs the operation of facilities used for the transmission of electric energy and provides transmission service]. As defined in the Electricity Act. [means the movement or transfer of electricity at voltages of 69 kilovolts or more over an interconnected group of lines and associated equipment between points of receipt and points of delivery to a consumer or to another electric system]. Transmission System As defined in the Electricity Act. [means a system for providing transmission service, and includes any structures, equipment or other things used for that service]. Version: 01 Page 10

68 Appendix A - Definitions Transmission User Has the meaning given to it in section 1.2. Transmitter Urgent Amendment Virtual Delivery Point Zone As defined in the Electricity Act. [(a) the Corporation, and (b) any other person who, immediately before the commencement of this definition, owned a transmission system within the Province as well as any subsequent owner of that transmission system]. An amendment to the Business Rule made in accordance with section 77 of the Electricity Act pertaining to urgent amendments. A notional point assigned by the SO for the purpose of allowing the submission of Balanced Schedules in respect of multiple Delivery Points. A part of the Integrated Electricity System that requires special consideration due to transmission constraints or voltage support requirements. Version: 01 Page 11

69 ELECTRICITY BUSINESS RULES Appendix B Connection Assessment Procedure

70 Connection Assessment Procedure Appendix B TABLE OF CONTENTS Part 1 For Future Use (Contact Information) Part 2 Introduction 2.1 Purpose of this Procedure 2.2 Scope and Application 2.3 Connection Applicant Responsibilities 2.4 Confidentiality Part 3 Overview 3.1 Feasibility Review 3.2 Determination of Needs 3.3 System Impact Study, Part 1: Local Impact Assessment 3.4 System Impact Study, Part 2: Network Impact Assessment 3.5 Facilities Study 3.6 Criteria for use in Assessments 3.7 Prioritization of Connections 3.8 Accuracy of, and Changes to, System Impact Studies and Facilities Studies 3.9 Related Connection Assessments Part 4 Process description 4.1 Project Definition - New or Modified Facility Connection 4.2 Feasibility Review - New or Modified Facility Connection 4.3 Determination of Need for Point-to-Point Service Requests 4.4 Application for System Impact Study 4.5 Conduct of System Impact Study - General Requirements 4.6 Third Party Impacts Version: 01 Page 2

71 Connection Assessment Procedure Appendix B Part 5 Part 6 Part 7 Part Waivers 4.8 SIS Report 4.9 Application for Facilities Study 4.10 Conduct of Facilities Studies - General Requirements 4.11 Facilities Study Report 4.12 Costs of Connection Assessments Timelines and Prioritization 5.1 Overview 5.2 Feasibility Review and Determination of Need 5.3 System Impact Study 5.4 Facilities Study 5.5 Commitment to Implement Cost Allocation 6.1 Principles of Cost Allocation 6.2 Cost Allocation Parameters 6.3 Review of Cost Allocation 6.4 Process for Challenge of Cost Allocation Flow Charts Process for Connection of New and Modified Facilities Forms B-01 Application for Feasibility Review for Generation and/or Loads B-02 Application for Feasibility Review for Transmission Lines and/or Substations B-03 System Impact Study Datasheet B-04 Application for Assessment in Respect of New Long-Term Point-to-Point Service B-05 System Impact Study Agreement B-06 Facilities Study Agreement Version: 01 Page 3

72 Connection Assessment Procedure Appendix B Part 2 Introduction 2.1 Purpose To set out the process by which Transmitters, Distributors, Transmission Users, or other persons may request the Transmission Provider to undertake assessments of connection to the Integrated Electricity System of new or materially modified Facilities. This procedure also provides detail with respect to the provisions of the Transmission Tariff sections 19 and 32 and Attachment D. 2.2 Scope and Application This procedure is applicable to all prospective and actual Connection Applicants. Connection Applicants may or may not be Transmission Users at the time of Connection Assessment, but will be required to complete the necessary agreements prior to the actual connection of any facility or the provision of service. This procedure is applicable in the case of all new or modified connections to the Integrated Electricity System. A Facility connection is considered to be materially modified if: A transformer is changed, A distribution feeder is added, or its breaker rating upgraded, Protection is changed, including breaker ratings or settings, Switchyard configuration changes such as electrical relocation of switches or breakers, Capacitors are added or removed, Load increase exceeding 1 MW, Generation is added, including embedded generation over 1 MW, or Other parameters of the connection or the facility connected are altered in a way that may impact the Integrated Electricity System. This procedure uses the term Connection Applicants to refer to both prospective and actual Connection Applicants. Version: 01 Page 4

73 Connection Assessment Procedure Appendix B The term Connection Applicant is also used in this procedure to include an Eligible Customer requesting long term Point to Point Service as provided in section 19 of the Transmission Tariff, where such Point to Point Service is beyond the transmission capacity posted by the Transmission Provider. It is assumed that any application for new Network Service as provided in section 32 of the Transmission Tariff will be associated with application for assessment of a new or modified Facility connection. This is not therefore separately identified in this Procedure. 2.3 Connection Applicant Responsibilities It is the responsibility of each prospective or actual Connection Applicant to: request the Transmission Provider to conduct a Feasibility Review, and make applications and execute contracts as required for System Impact Studies and Facilities Studies; pay deposits and invoiced fees; undertake all design of any connection proposal, including liaison as required with the responsible transmitter, and to provide the requisite information to the Transmission Provider; respond promptly to any queries or additional information requests; secure all other authorizations required; and In order to maintain queue position, proceed with subsequent stages and to implementation within the prescribed timelines. 2.4 Confidentiality Public items List of System Impact Study requests and applications received (Connection Applicant, date of receipt of complete application, brief description, connection location), together with ongoing status updates and Connection Application date stamp. Version: 01 Page 5

74 Connection Assessment Procedure Appendix B System Impact Study Reports (excluding report appendices containing Confidential Information). Confidential items Feasibility Reviews (requests, existence, and reports) Needs Assessments Connection Applications and supporting information (but not the existence of the application or the reports thereon) Appendices to System Impact Study Reports containing Confidential Information Facilities Study Reports Study costs and payments Part 3 Overview 3.1 Feasibility Review Feasibility Review provides an opportunity for early identification of Any problems with the proposed Facility design, All grid-related information needed by the Connection Applicant to design the Facility connection, and all information required by the Transmission Provider to complete the System Impact Study, and Any likely non-standard design requirements for the new or modified Facility Feasibility Review includes determination of needs Feasibility review is mandatory with respect to new or modified Facility connections, but (until revision of the tariff) not with respect to Point to Point Service requests. Version: 01 Page 6

75 Connection Assessment Procedure Appendix B 3.2 Determination of Needs The Transmission Provider will determine what assessments and studies are or may be needed in order to complete a particular System Impact Study The Transmission Provider will estimate the cost and time requirements of such assessments and studies The Transmission Provider may determine that it will (on application) be able to issue a Connection Approval without System Impact Study. 3.3 System Impact Study - Part 1: Local Impact Assessment Local Impact Assessment comprises the assessment of the connection proposal s impact on local load flows, fault levels etc,. in order to determine if the new or modified Facility connection is designed to the necessary standards and if its implementation would require modification of other local connections Local Impact Assessment is not applicable to a request for new Point to Point Service between existing points unless required by virtue of a planned modification to a Facility connection. 3.4 System Impact Study Part 2: Introduction Network Impact Assessment comprises the assessment of the Integrated Electricity System to determine: if the connection proposal could be accommodated without reducing bulk transfer limits on the grid; and Version: 01 Page 7

76 Connection Assessment Procedure Appendix B if consequential load flows would add to grid congestion, and if so, what operating constraints or grid enhancement would mitigate this impact. This may result in a number of options. 3.5 Facilities Study Facilities Study comprises the design and estimation of cost and time requirements of those measures necessary to mitigate negative impacts identified in Local Impact Assessment or Network Impact Assessment in order to accommodate the Facility connection Facilities Study includes estimated costs and their allocation. 3.6 Criteria for Use in Assessments The criteria to be used in each assessment are set out in the Transmission Providers planning criteria. 3.7 Prioritization of Connections It is recognized that the transmission resource available to support new connections may be limited, and that the allocation of any rights to use of such existing resources must be definitive and non-discriminatory. The process used by the Transmission Provider to achieve this is described in section 5 of this Procedure. 3.8 Accuracy of, and Changes to, System Impact Studies and Facilities Studies It is recognized that the Connection Assessment may be undertaken early in the project development and design, and that design parameters may not be fully developed at the Version: 01 Page 8

77 Connection Assessment Procedure Appendix B time of the application. The Connection Applicant shall make its best efforts to provide accurate information at all stages, and to keep the Transmission Provider advised of updates. The Connection Applicant may use typical range data where appropriate, in which case the Transmission Provider will generally use the worst case values in its assessments. The Transmission Provider will accept normal design development changes during the course of its assessments, but may incur extra cost and time which shall be to the applicant s account In the event that a Connection Applicant provides changed or additional information that substantively changes the project, or that introduces material adverse impact on the connection or system, then the Transmission Provider may, on reasonable notice to the Connection Applicant, deem the original application to have been withdrawn. In such a case, the Connection Applicant may make a new application for System Impact Study with the revised data. 3.9 Related Connection Assessments Connection Assessments are considered to be related if the (assumed or actual) implementation of one connection (or Point to Point Service request) would alter the results of any assessment or study of the other The Transmission Provider will judge the most appropriate treatment of related prior Connection Assessments when undertaking any assessment, and will consult as appropriate with the new Connection Applicant in making such judgment The Transmission Provider may combine the Network Impact Assessments of related Connection Assessment if it considers this appropriate from technical, timing, and workload considerations. Version: 01 Page 9

78 Connection Assessment Procedure Appendix B Part 4 Process Description 4.1 Project Definition New or Modified Facility Connection The Connection Applicant shall prepare the Facility and connection design Nothing in this Procedure is intended to preclude or limit direct consultation between the Connection Applicant and the Transmission Provider prior to application for a Feasibility Review. In the case of modified Facilities the Transmission Provider will advise if the modification may be materially impactive prior to such submission for review. 4.2 Feasibility Review New or Modified Facility Connection A Connection Applicant is required to request a Feasibility Review of a new or modified Facility connection, and shall use the application Form B-01 and/or Form B-02 for this purpose. A separate application is required for each project For new connections involving non-embedded generation projects, the Connection Applicant shall submit to the Transmission Provider a non-refundable application fee of $5,000 per project plus taxes with the application, together with the basic information on each project. For other projects, including, embedded generation projects, and assessments of Point to Point transmission service greater than 100 MW, the non-refundable application fee is also $5,000 plus taxes. For all other projects, the application fee is zero The Feasibility Review is intended as an informal process whereby a Connection Applicant requests, and the Transmission Provider undertakes, a review of a connection scheme proposed by a Connection Applicant The Feasibility Review is not intended to substitute for or in any way mitigate the Connection Applicant s responsibility for design, but is intended to facilitate a subsequent System Impact Study through the early identification and communication of Any problems with proposed connection design, Version: 01 Page 10

79 Connection Assessment Procedure Appendix B All grid-related information needed by the Connection Applicant to design the connection, Any likely non-standard design requirements for the particular new or modified Facility connection, and All information required by the Transmission Provider to complete a System Impact Study The Transmission Provider shall undertake a determination of need in conjunction with a Feasibility Review The Transmission Provider has the right to limit the scope of a Feasibility Review if this would otherwise impose excessive cost or workload on the Transmission Provider Findings of a Feasibility Review will be communicated to the Connection Applicant in a report comprising: Findings of the review with respect to the proposed design; Grid-related information that the Connection Applicant will need to design the Facility and the connection; Description of information required by the Transmission Provider to complete a System Impact Study; Draft schedule A to a SIS agreement (Form B-05), setting out Connection Applicant description Project name and brief description SIS cost and time estimate SIS deposit amount, and Providing for sign off as part of the SIS application The conduct by the Transmission Provider of a Feasibility Review has no bearing on the prioritization of a project past the completion of the Feasibility Review If the Transmission Provider has determined in a Feasibility Review that a new or modified facility connection can be approved without a System Impact Study, then this will be Version: 01 Page 11

80 Connection Assessment Procedure Appendix B indicated as part of the Feasibility Review. The Connection Applicant is still required to submit a complete application for a Facilities Study in order to secure the Transmission Provider s approval of the new or modified facility connection, and in order to secure the date stamp, a basis for prioritization and cost allocation The existence and results of a Feasibility Review are confidential except to the extent that the Transmission Provider may procure services or assistance from the Transmitter, and except in cases where the Connection Applicant permits communication with others to facilitate the Feasibility Review. 4.3 Determination of Need for Point-to-Point Service Requests If an eligible customer seeks new long term Point to Point Service under the tariff provisions that do not presently require a Feasibility Review, then the Transmission Provider shall undertake the determination of need to establish if the service can be provided from existing facilities, or if a System Impact Study is needed. If a System Impact Study is needed, then the Transmission Provider shall provide a draft schedule A to a SIS agreement (FormB- 05), setting out Connection Applicant description Description of service requested SIS cost & time estimate SIS deposit amount, and Providing for sign off as part of the SIS application. 4.4 Application for System Impact Study The Connection Applicant shall use form App-B-03 to apply for a System Impact Study in respect of a new or modified Facility connection or form App-B-04 in respect of Point to Point service not associated with a new or modified connection. Version: 01 Page 12

81 Connection Assessment Procedure Appendix B The application shall be considered complete on receipt by the Transmission Provider of: Completed Form B-03 or Form B-04; Executed System Impact Study Agreement (Form: B-05), as provided by the Transmission Provider in a Feasibility Review or Determination of Need (subject to section below); Deposit in the amount shown in the SIS Agreement; and All information required by the Transmission Provider to complete the System Impact Study The Transmission Provider shall promptly advise the Connection Applicant if it considers an application to be incomplete The Transmission Provider shall promptly reject any application if it considers that the SIS Agreement is no longer applicable due to changes in circumstances since the completion of the Feasibility Review or determination of need The Transmission Provider shall promptly register any complete application not rejected in accordance with section 4.4.4, and shall record the date and time on which it received the complete application. This date and time constitute the date stamp of the application. 4.5 Conduct of System Impact Studies General Requirements The general criteria to be used by the Transmission Provider in a System Impact Study are set out in the Transmission Provider s planning criteria. These criteria are based on NPCC and NERC requirements and good utility practice. The Transmission Provider may impose requirements more rigorous criteria if it considers such requirements necessary for Reliability and non-discriminatory access to the Integrated Electricity System The System Impact Study shall: Incorporate the current Baseline Plan established in accordance with chapter 2 of the Electricity Business Rules, (subject to reasonable inclusion of information relating to any new Baseline Plan in preparation), Version: 01 Page 13

82 Connection Assessment Procedure Appendix B Incorporate other new or modified Facility connections that have been committed for implementation, Incorporate other related new or modified Facility connections that are in the opinion of the Transmission Provider likely to be committed for implementation prior to completion of the System Impact Study, or otherwise likely to be committed to have priority over the project under study. Reflect long term Point to Point Transmission Service commitments, and To the extent practical, include sensitivity analysis with respect to other related new or modified Facility connections with earlier date stamps The Transmission Provider may rely on services or assistance from the relevant Transmitters to provide information and conduct analysis The Transmission Provider may communicate with the Connection Applicant in order to secure clarification or resolve issues The Connection Applicant shall promptly provide any additional information requested and communicate any decisions required to resolve issues The Connection Applicant may update or modify its design in the normal course of design progress, or to resolve issues identified to it by the Transmission Provider. In the case of a change that substantively changes the project, or that introduces material adverse impact on the connection or system, then the Transmission Provider may on reasonable notice to the Connection Applicant (not less than 10 business days), deem the original application to have been withdrawn In the event that requested information or decisions are not forthcoming, the Transmission Provider may give notice that, unless the situation is remedied within a specified period (no less than 10 business days) the Connection Application will be deemed to have been withdrawn. Version: 01 Page 14

83 Connection Assessment Procedure Appendix B 4.6 Third Party Impacts A new or modified Facility connection may give rise to changes by which existing third party facilities (i.e. those owned by, or leased to, other Transmission Users) become noncompliant with design standards or codes In completing the Local Impact Assessment, the Transmission Provider will seek to identify any such instances, based on its knowledge and based on enquiry as appropriate to other Transmission Users with local connections. Engineering studies of such identified third party impacts will be deferred to any Facilities Study. 4.7 Waivers The Connection Applicant may during its design work identify benefits arising from a waiver of a particular standard or code in a manner that would not jeopardize the Reliability of the Integrated Electricity System. 4.8 SIS Report The SIS report shall record either: In the case of an application under section above, the Transmission Provider s confirmation of approval of a new or modified facility connection; The Transmission Provider s approval of the application, subject to system upgrades; The Transmission Provider s approval of the application subject to system upgrades and other technical or operational conditions; or The Transmission Provider s rejection of the application with reasons. Version: 01 Page 15

84 Connection Assessment Procedure Appendix B The SIS report shall include the project description, single line diagrams, design parameters, etc., except for such details of site location or design parameters that in the opinion of the Transmission Provider can be withheld without prejudice to the integrity and completeness of the report, and should be withheld to avoid prejudice to the commercial interests of the Connection Applicant. Examples of such information that may thus be held confidential are: Site location (but not grid connection point) of a project Equipment design parameters whose publication would prejudice forthcoming procurement processes The SIS report shall identify any other studies referenced in the present study, and shall describe the new studies performed and their results The SIS report shall identify if the Connection Applicant would incur liability to compensate any prior Connection Applicant for use of facilities funded by that prior Connection Applicant The SIS report shall identify Facilities Studies required in order to finalize the connection design and any system or third party upgrades required The Transmission Provider may review a draft SIS report with the Connection Applicant if the Transmission Provider considers that this would be beneficial The SIS report shall record the date stamp of the application, as well as the SIS report date, which is the date on which the report is completed by the Transmission Provider The Transmission Provider shall make the final SIS report available to the public after providing it to the Connection Applicant The Transmission Provider shall provide to the Connection Applicant a draft schedule A to a Facilities Study agreement (Form B-04), setting out: Connection Applicant description; Description of project; Scope of Facilities Study required (may include options depending on decisions by the Connection Applicant); Version: 01 Page 16

85 Connection Assessment Procedure Appendix B Facilities Study cost & time estimate; Facilities Study deposit amount; and Providing for sign off as part of the Facilities Study application. 4.9 Application for Facilities Study The Connection Applicant shall apply in writing to the Transmission Provider for a Facilities Study following issue of a System Impact Study report. The Connection Applicant shall at this time indicate selection of any options indicated in the SIS report The application shall be considered complete on receipt by the Transmission Provider of: Completed Form B-01 and/or Form B-02; Executed Facilities Study Agreement (Form B-06), as provided by the Transmission Provider at the time of the SIS report (subject to section below); Deposit in the amount shown in the FS Agreement, and All information required by the Transmission Provider to complete the Facilities Study The Transmission Provider shall promptly advise the Connection Applicant if it considers an application to be incomplete The Transmission Provider shall promptly reject any application if it considers that schedule A is no longer applicable due to changes in circumstances since the completion of the SIS The Transmission Provider shall promptly register any complete application not rejected in accordance with section and shall record the date and time on which it received the complete application. This date and time constitute the date stamp of the FS application If the Connection Application has no prior date stamp, then the FS date stamp shall become the date stamp of the Connection Application. Version: 01 Page 17

86 Connection Assessment Procedure Appendix B 4.10 Conduct of Facilities Studies General Requirements The general criteria to be used by the Transmission Provider in a Facilities Study are set out in the Transmission Provider s planning criteria. These criteria are based on NPCC and NERC requirements and in accordance with good utility practice. The Transmission Provider may determine facility requirements more rigorous than the general criteria if indicated by the SIS The Facilities Study shall: Incorporate the current Baseline Plan established in accordance with Chapter 2 of the Electricity Business Rules, (subject to reasonable inclusion of information relating to any new Baseline Plan in preparation), Incorporate other new or modified Facility connections that have been committed for implementation, Incorporate other related new or modified Facility connections that are in the opinion of the Transmission Provider likely to be committed for implementation prior to completion of the System Impact Study, or otherwise likely to be committed to have priority over the project under study. Reflect long term Point to Point Transmission Service commitments, and To the extent practical, include sensitivity analysis with respect to other related new or modified Facility connections with earlier date stamps. Include cost estimates and allocations To the extent that there is any waiver Application under consideration, the Transmission Provider shall consult with the Connection Applicant to establish the appropriate assumptions To the extent that a Facilities Study depends on information or clarification from the Connection Applicant, the Connection Applicant shall provide such information or clarification promptly in response to any request. In the event that requested Version: 01 Page 18

87 Connection Assessment Procedure Appendix B information or decisions are not forthcoming, the Transmission Provider may give notice that, unless the situation is remedied within a specified period (no less than 10 business days) the Connection Application will be deemed to have been withdrawn 4.11 Facilities Study Report The Facilities Study report shall set out: The nature and design of the facilities and upgrades required to accommodate a new or modified Facility connection or new Point-to-Point Service; The nature and design of any third party facilities or upgrades required to permit implementation of a new or modified connection; The costs estimates (including all assumptions and detailed calculations) and schedule to implement the above facilities and upgrades; The Transmission Provider s allocation of responsibility for the costs, including the basis of such determination; and Any uncertainties with respect to time, cost, or cost allocation (e.g. arising from uncertainty over implementation of prior projects or cost recovery from subsequent projects) The SIS report shall record the date stamp of the application The Transmission Provider may review a draft Facilities Study report with the Connection Applicant if the Transmission Provider considers that this would be beneficial The Facilities Study report shall record the Connection Application date stamp as well as the FS report date, which is the date on which the report is completed by the Transmission Provider The Facilities Study report is confidential unless released by the Connection Applicant. Version: 01 Page 19

88 Connection Assessment Procedure Appendix B The Transmission Provider shall publish the date stamp of the Facilities Study application and the Facilities Study report date Costs of Connection Assessments The Transmission Provider will record actual costs of System Impact Studies and Facilities Studies and will invoice these costs to Connection Applicants, net of deposit amounts, within a week of the completion of each report or of any earlier termination of a study The Connection Applicant shall pay such invoiced amounts owing within 30 Business Days of invoicing by the Transmission Provider The Transmission Provider shall pay any amounts owing to a Connection Applicant as a result of costs less than deposit amounts, within 30 Business days of invoicing The principles of cost sharing as described in the Tariff, Attachment K, shall also apply to the Connection Assessment Costs and the Transmission User will be refunded accordingly. Part 5 Timelines and Prioritization 5.1 Overview The capabilities of the existing system are essentially allocated on a first-come, firstserved basis. The use of date stamps for the prioritization of applications is designed to support this, and to provide a basis for allocation of costs that are required to be incurred to permit new or modified Facility connections to be made without jeopardy to the Reliability of the Integrated Electricity System The date stamp of a Connection Application (including an application for Point to Point Service) is first awarded on receipt by the Transmission Provider of the complete application for System Impact Study as noted in section above. Version: 01 Page 20

89 Connection Assessment Procedure Appendix B A Connection Application is deemed to lapse, and thus to lose its date stamp, if the Connection Applicant fails to maintain progress on the project in accordance with the deadlines set out in this Part 5 of this Procedure A Connection Applicant may secure a new date stamp by submitting a new application for System Impact Study or Facilities Study as appropriate The date stamp thus defines the scope and cost of work to implement a new or modified facility connection or new Point to Point Service, and potentially the allocation of cost responsibility as discussed in Part 6 of this Procedure. 5.2 Feasibility Review and determination of need The Feasibility Review and determination of need are typically expected to be complete within two weeks of a completed application, but this will depend on the workload of the Transmission Provider and of any Transmitter s resources required to undertake the review. In view of the uncertainties associated with projects at this early stage, the Transmission Provider s obligation is general diligence rather than specific timelines The Feasibility Review and determination of need have no fixed validity period. If there has been material change in circumstances between the completion of the Feasibility Review / determination of need and the application for System Impact Study, then the Transmission Provider may reject the SIS application in accordance with section above, and require that the Connection Applicant undertake an updated Feasibility Review or determination of need as a basis of an acceptable application for System Impact Study. This may arise through the passage of significant time, or as a result of other Connection Applications. 5.3 System Impact Study The date stamp of a Connection Application is first established in accordance with section above on the Transmission Provider s receipt of a complete application for System Impact Study. Version: 01 Page 21

90 Connection Assessment Procedure Appendix B Connection Applications for System Impact Studies are placed into two separate queues; (i) the generation SIS queue, and (ii) the load SIS queue. The generation SIS queue will include all projects that involve the connection of new non-embedded generation to the IES. The load SIS queue will include all other projects, including the connection of load projects, embedded generation projects, and assessments of new Point to Point transmission service The undertaking of System Impact Studies will be based on the following priority: System Impact Studies in the generation SIS queue and the load SIS queue have equal priority, and will be worked on concurrently. Transmission reservation status First priority in both the generation SIS queue and the load SIS queue will be given to projects associated with firm transmission service. The Transmission Provider will associate a project with firm transmission service if it meets the following criteria: The transmission service must be firm for at least five years, and The transmission service must be for at least 50% of the project size, and The project may acquire transmission service directly or indirectly by contracting with another Transmission User who can provide the transmission service. For projects that are equal in terms of transmission reservation status, the Transmission Provider will undertake System Impact Studies in the order of their date stamps. The Transmission Provider may choose to group related applications for efficiency or workload considerations, but shall continue to assume that implementation would follow date stamp order The Transmission Provider will endeavor to complete System Impact Studies in accordance with the time estimates set out in schedule A of the agreement. It is expected that these will typically be in the order of one month, but this will depend on the workload of the Transmission Provider and of any transmitter s resources required to undertake the review. Version: 01 Page 22

91 Connection Assessment Procedure Appendix B In view of the uncertainties associated with projects at this early stage, the Transmission Provider s obligation is general diligence rather than specific timelines Sections and set out obligations with respect to a Connection Applicant s performance during a System Impact Study. A Connection Application that lapses or is deemed to be withdrawn in accordance with those sections loses its date stamp The System Impact Study and the time and cost estimates for Facilities Study have a specified validity of 30 days from the report date as defined in section 4.9.7, or if that day is not a Business Day, until the next Business Day thereafter. The Transmission Provider may extend such validity only in circumstances where this would not cause harm to another Connection Applicant and where there is no material change in the parameters on which the SIS was based. 5.4 Facilities Study If the Transmission Provider receives a complete application for Facilities Study within the validity period (original or extended) of the SIS, then the date stamp of the Connection Application shall continue to be the date stamp established under section If the Transmission Provider receives a complete application for FS in respect of a Connection Application for which there is no valid date stamp, then the Connection Application date stamp shall be the FS application date stamp in accordance with section The Transmission Provider will generally undertake Facilities Studies in the order of their Connection Application date stamps. The Transmission Provider may choose to group related applications for efficiency or workload considerations, but shall continue to assume that implementation would follow date stamp order The Transmission Provider will endeavor to complete Facilities Studies in accordance with the time estimates set out in the FS agreement. It is expected that these will typically be in the order of one month, but this will depend on the workload of the Transmission Provider and of any Transmitter s resources required to undertake the review. In view of the Version: 01 Page 23

92 Connection Assessment Procedure Appendix B uncertainties associated with projects at this early stage, the Transmission Provider s obligation is general diligence rather than specific timelines Section sets out obligations with respect to a Connection Applicant s performance during a Facilities Study. A Connection Application that lapses or is deemed to be withdrawn in accordance with that section loses its date stamp A Facilities Study has a specified validity of three months. The Transmission Provider may extend such validity only in circumstances where this would not cause harm to another Connection Applicant and where there is no material change in the parameters on which the Facilities Study or the underlying System Impact Study were based. 5.5 Commitment to implement The Connection Applicant may make a commitment to the implementation of the project and the Facilities defined in the Facilities Study, within the validity of the Facilities Study. Unless such a commitment is made in accordance with the following provisions, the Connection Applicant will not be permitted to synchronize its new or modified Facility connection, or to contract for Point to Point Service, as applicable Such a commitment must include: The making of a financial commitment to the transmitter for the construction of all transmission system upgrades specified in the Facilities Study, The commitment to the Transmission Provider that the connection will be constructed in accordance with the requirements of the System Impact Study and the Facilities Study, and the making of financial commitments for such construction, The commitment to the Transmission Provider that the Connection Applicant will secure the modification of third party facilities as specified in the Facilities Study Version: 01 Page 24

93 Connection Assessment Procedure Appendix B The commitment to the Transmission Provider that the facility will be constructed and operated in accordance with any relevant conditions of the System Impact Study Notice to the Transmission Provider that the project is proceeding, and notification of the project schedule. Part 6 Cost Allocation 6.1 Principles of cost allocation The allocation of the costs of connections and of associated changes to the IES shall be in accordance with the Tariff cost sharing principles. Part 7 Flow Charts Refer to next page for the flow chart: Process for Connection of New and Modified Facilities) Version: 01 Page 25

94 Connection Assessment Procedure Appendix B Process for Connection of New and Modified Facilities Start 2) Preliminary Feasibility Study 1) New or Updated Transmission Service Agreement 1a) Network Service Agreement 1b) Long-Term Firm Point-to-Point Service Agreement 1c) Short-Term Firm or Non-Firm Point-to-Point Service Agreement Note: Step 1 is carried out concurrently with steps 2, 3, 4 and 5 3) 1-Line Diagram 4) System Impact Study 5) Facilities Study 6) New or Updated Connection Agreement 6a) Network Operating Agreement (Load) 6b) Generation Connection Agreement (Generator) 7) Commissioning 8) Approval End Version: 01 Page 26

95 Appendix B Connection Assessment Procedure Part 8 Forms B-01 Application for Feasibility Review for Generation and/or Loads B-02 Application for Feasibility Review for Transmission Lines and/or Substations B-03 System Impact Study Datasheet B-04 Application for Assessment in Respect of New Long-Term Point-to-Point Service B-05 System Impact Study Agreement B-06 Facilities Study Agreement Version: 01 Page 27

96 FORM: B-01 Connection Assessment Procedure Connection Applicant Form (B-01) Application for Feasibility Review for Generation and/or Load Proponent Project Description of the project to be studied. Type Size (MW) Location PCC Voltage Longitude Latitude Map Datum PID (e.g. Coal plant, Wind farm, etc.) kv Connection Option Selected Connection to the Transmission System. Line Number Voltage (kv) Distance from project (km) kv km Continued on next page Version: 01 Page 1 Effective: October 1, 2013

97 FORM: B-01 Connection Assessment Procedure Service Type of transmission services requested. Services Requested Customer Expected in-service date (Point-to-Point or Network Services) Version: 01 Page 2 Effective: October 1, 2013

98 FORM: B-02 Connection Assessment Procedure Connection Applicant Form (B-02) Application for Feasibility Review for Transmission Lines and/or Substations 1. Applicant Date 2. General Description of Project: 3. Type of Facility In-Service Date 4. Transmission Line or Substations a) From To (Terminal Name - Location) (Terminal Name Location) b) Third terminal or tap (if any) c) Distance km Voltage kv Conductor size d) Type of line relaying Backup relaying Breaker Failure SPS Version: 01 Page 1

99 FORM: B-02 Connection Assessment Procedure 4. Transformer rating MVA HV LV Tertiary kv kv kv Resistance Reactance 5. Attach simplified one-line diagram of transmission/substation with breaker configuration. 6. List facility ratings 7. Reliability Studies completed (if required) Short Circuit Load Flow Stability Other Version: 01 Page 2

100 FORM: B-03 Connection Assessment Procedure Connection Applicant Form (B-03) System Impact Study Data Sheet Proponent Project Description of the project to be studied. Type Size (MW) Location PCC Voltage Longitude Latitude Map Datum PID (e.g. Coal plant, Wind farm, etc.) kv Connection Option Selected Connection to the Transmission System. Line Number Voltage (kv) Distance from project (km) kv km Continued on next page Version: 01 Page 1 Effective Date: Octtober 1, 2013

101 FORM: B-03 Connection Assessment Procedure Service Type of transmission services requested. Services Requested Customer Expected in-service date Point-to-Point or Network Services Generators Generator characteristics. Manufacturer Model Type Voltage (kv) Max MW Max MVA Power Factor Frequency Number of generators 60 Hz Transformers Step-up transformer data. Rating / / MVA Voltage kv / kv Configuration Taps (Number and Range) ± x % Impedance (on 100 MVA base) % X/R Ratio Number of transformers Continued on next page Version: 01 Page 2 Effective Date: Octtober 1, 2013

102 FORM: B-03 Connection Assessment Procedure Unit Transformers Unit transformer data. Rating / MVA Voltage kv / kv Configuration Taps (Number and Range) ± x % Impedance (on 100 MVA base) % X/R Ratio Breakers Circuit breakers information Primary voltage level Voltage Number of breakers Secondary voltage level Voltage Number of breakers kv kv Version: 01 Page 3 Effective Date: Octtober 1, 2013

103 FORM: B-03 Connection Assessment Procedure One-Line Diagram Continued on next page Version: 01 Page 4 Effective Date: Octtober 1, 2013

104 FORM: B-03 Connection Assessment Procedure Proposed Generation Facility One- Line Diagram PSS/E Model Power System Simulation (PSS/E) software. PSS/E model supplied? Confirmation Signature: Date: Title: Version: 01 Page 5 Effective Date: Octtober 1, 2013

105 FORM: B-04 Connection Assessment Procedure Connection Applicant Form (B-04) Application for Assessment in Respect of New Long-Term Point-to-Point Service Transmission Provider Transmission User Company Name: Contact 1: Address: Telephone: Fax: Version: 01 Page 1

106 FORM: B-04 Connection Assessment Procedure Contact 2: Address: Telephone: Fax: Specifications for Long-Term Point-to-Point Transmission Service 1. Term of Transmission: Start Date: Termination Date: 2. Description of capacity and energy to be transmitted by Transmission Provider including the electric Control Area in which the transaction originates. Options to be studied: Option 1: Version: 01 Page 2

107 FORM: B-04 Connection Assessment Procedure Option 2: 3. Point-of-Receipt: Point-of-Receipt Option 1 Option 2 Delivering Party Capacity Reservation to be reserved and posted at Point(s) of Receipt 4. Point-of-Delivery: Point-of-Delivery Option 1 Option 2 Receiving Party Capacity Reservation to be reserved and posted at Point(s) of Delivery Version: 01 Page 3

108 FORM: B-04 Connection Assessment Procedure 5. Maximum amount of capacity and energy to be transmitted: Reserved Capacity Option 1 Option 2 Energy 6. Name(s) of any Intervening Systems providing transmission service: 7. Designation of parties subject to reciprocal service obligation: 8. Service under this Agreement may be subject to some combination of the charges detailed below. (The approximate charges for individual transactions will be determined in accordance with the terms and conditions of the Tariff.) Version: 01 Page 4

109 FORM: B-04 Connection Assessment Procedure 8.1. Transmission Charge: 8.2. System Impact and/or Facilities Study Charges(s): 8.3. Direct Assignment Facilities Charge: 8.4. Ancillary Service Charges: Load following: Scheduling, system control and dispatch service: Option 1: Option 2: Reactive supply and voltage control from generation source: Automatic generation control: Version: 01 Page 5

110 FORM: B-04 Connection Assessment Procedure Load Following: Operating reserve spinning reserve service: Operating Reserve Services: Version: 01 Page 6

111 FORM: B-05 Connection Assessment Procedure Connection Applicant Form (B-05) System Impact Study Agreement System Impact Study Agreement project name This Agreement made this day of in the year. BETWEEN: (the Connection Applicant ). AND NEW BRUNSWICK POWER CORPORATION having its head office at the city of Fredericton, Province of New Brunswick Both of which may hereinafter be referred to as a Party or collectively as the Parties WHEREAS: A. The Connection Applicant proposes to connect to the Integrated Electricity System at or near a location known as. Version: 01 Page 1 Effective: October 1, 2013

112 FORM: B-05 Connection Assessment Procedure B. Any additions to the Integrated Electricity System are subject to the requirements of the Open Access Transmission Tariff (the Tariff). C. The Tariff requires that a System Impact Study be conducted respecting any proposed additions to the Integrated Electricity System. D. The Connection Applicant has requested the Transmission Provider conduct a System Impact Study respecting its proposal. NOW THEREFORE, in consideration of the mutual covenants set forth herein, and other good and valuable consideration, the Parties agree as follows: 1. a) Except where otherwise defined in this Agreement, capitalized terms used in this Agreement shall have the meaning ascribed to them in the Tariff, including Attachment J thereto. b) Integrated Electricity System has the meaning ascribed to it in the Electricity Act. 2. The Transmission Provider shall cause a System Impact Study to be conducted in accordance with the Tariff. 3. The scope of the System Impact Study shall be as defined and described in the attached Schedule A of this Agreement. 4. Connection Applicant agrees to provide to the Transmission Provider all technical data or other information specifically noted in Schedule A. The Transmission Provider reserves the right to request additional technical data or information as it determines is necessary during the course of the System Impact Study and Connection Applicant agrees to provide all such additional technical data or information. Version: 01 Page 2 Effective: October 1, 2013

113 FORM: B-05 Connection Assessment Procedure 5. Connection Applicant agrees to pay all costs and expenses incurred, directly or indirectly, by or on behalf of the Transmission Provider in conducting the System Impact Study. Transmission Provider s estimate of the total cost to Connection Applicant is Dollars Cdn., plus all applicable taxes. The Transmission Provider agrees to promptly notify Connection Applicant of any material change in this estimate. 6. Payment of costs and expenses referred to in Article 5 above shall include an initial payment of Dollars Cdn., payable prior to the commencement of the System Impact Study. Subject to Articles 7 and 10 herein, payment of remaining amounts owing will be due upon completion of the System Impact Study. 7. Connection Applicant may at any time withdraw its request for the completion of the System Impact Study and in such event shall be liable to the Transmission Provider only for all costs incurred by or on behalf of Transmission Provider up to the date of receipt of Connection Applicant s withdrawal notification. 8. The Transmission Provider agrees to make its best effort to complete the System Impact Study in a timely manner and in accordance with Good Utility Practice. Under no circumstances, however, shall the Transmission Provider be liable to the Connection Applicant for any loss, damage, claim, cost, charge or expense, whether direct, indirect, incidental, punitive, special or consequential arising from the 9. Transmission Provider s performance or non-performance of its obligations under this Agreement, except in the case of gross negligence or willful misconduct on the part of the Transmission Provider, in which case the Transmission Provider s liability to the Connection Applicant shall be limited to the amount paid by the Connection Applicant to the Transmission Provider pursuant to Article 5 herein. 10. The provisions of section 10.2 of the Tariff respecting Indemnification apply to this Agreement and are hereby incorporated by reference herein, with all references in such section to Transmission User being deemed to be referenced to the Connection Applicant, and all references in such section to Transmission Provider being deemed to the references to the Transmission Provider. Version: 01 Page 3 Effective: October 1, 2013

114 FORM: B-05 Connection Assessment Procedure 11. Results of the System Impact Study shall not be released until arrangements satisfactory to the Transmission Provider have been made for the payment of all costs and expenses referred to in Article 5 above. 12. The Connection Applicant acknowledges that notice of completion of the System Impact Study will be posted on the Transmission Provider's web site and the final results will be available to others upon submission of a request to the Transmission Provider. 13. Connection Applicant acknowledges and agrees that the results of the System Impact Study are estimates only and that actual connection to the Integrated Electricity System is subject to the terms and conditions of a Generator Connection Agreement, which agreement must be substantially in the form of Attachment J of the Tariff, entered into between the Connection Applicant and New Brunswick Power Corporation. 14. This Agreement shall inure to the benefit of and be binding upon the Parties and their respective successors and permitted assigns. 15. This Agreement shall be governed by and construed in accordance with the laws of the Province of New Brunswick. 16. Any notices required under this Agreement must be in writing and shall be made to the appropriate Party s representative as indicated below: In the case of the Transmission Provider: New Brunswick Power Corporation 515 King St. Fredericton, NB E3B 4X1 Attention: In the case of the Connection Applicant: Version: 01 Page 4 Effective: October 1, 2013

115 FORM: B-05 Connection Assessment Procedure IN WITNESS WHEREOF the Parties have caused this Agreement to be executed by their respective authorized officials as of the date first above written. (the Connection Applicant ) NEW BRUNSWICK POWER CORPORATION BY: BY: NAME: NAME: TITLE: TITLE: Version: 01 Page 5 Effective: October 1, 2013

116 FORM: B-06 Connection Assessment Procedure Connection Applicant Form (B-06) Facilities Study Agreement Facilities Study Agreement project name This Agreement made this day of in the year. BETWEEN: (the Connection Applicant ) AND NEW BRUNSWICK POWER CORPORATION, having its head office at the City of Fredericton, Province of New Brunswick. Both of which may hereinafter be referred to as a Party or collectively as the Parties. WHEREAS: A. The Connection Applicant proposes to interconnect to the Integrated Electricity System near, NB. B. Any additions to the Integrated Electricity System are subject to the requirements of the Open Access Transmission Tariff (the Tariff ). C. The Tariff requires that a System Impact Study be conducted respecting any proposed additions to the Integrated Electricity System. Version: 01 Page 1

117 FORM: B-06 Connection Assessment Procedure D. The required System Impact Study was conducted pursuant to an agreement between the Parties dated E. The Connection Applicant has requested the Transmission Provider conduct a Facilities Study respecting its proposal. NOW THEREFORE: In consideration of the mutual covenants set forth herein, and other good and valuable consideration, the Parties agree as follows: 1. a) Except where otherwise defined in this Agreement, capitalized terms used in this Agreement shall have the meaning ascribed to them in the Tariff, including Attachment J thereto. b) Integrated Electricity System has the meaning ascribed to it in the Electricity Act 2. The Transmission Provider shall cause a Facilities Study to be conducted in accordance with the Tariff. 3. The Facilities Study shall be based upon the result of the System Impact Study. The scope of the Facilities Study and the contents of the final Facilities Study report shall be as defined and described in the attached Schedule A of this Agreement. 4. Connection Applicant agrees to provide to the Transmission Provider all technical data or other information required, in the opinion of the Transmission Provider, to conduct the Facilities Study. Transmission Provider reserves the right to request additional technical data or information as it determines is necessary during the course of the Facilities Study and Connection Applicant agrees to provide all such additional technical data or information. 5. Connection Applicant agrees to pay all costs and expenses incurred, directly or indirectly, by or on behalf of the Transmission Provider in conducting the Facilities Study. Transmission Provider s estimate of the total cost to Connection Applicant is Dollars Cdn., plus all applicable taxes. Transmission Provider agrees to promptly notify Connection Applicant of any material change in this estimate. Version: 01 Page 2

118 FORM: B-06 Connection Assessment Procedure 6. Payment of costs and expenses referred to in Article 5 above shall include an initial payment of Dollars Cdn., payable prior to the commencement of the Facilities Study. Subject to Articles 7 and 10 herein, payment of remaining amounts owing will be due upon completion of the Facilities Study. 7. Connection Applicant may at any time withdraw its request for the completion of the Facilities Study and in such event shall be liable to the Transmission Provider only for all costs incurred by or on behalf of Transmission Provider up to the date of receipt of Connection Applicant s withdrawal notification. 8. The Transmission Provider agrees to make its best effort to complete the Facilities Study in a timely manner. Under no circumstances, however, shall the Transmission Provider be liable to Connection Applicant for any costs or damages Connection Applicant suffers or alleges it has suffered as a result of the timeliness of the completion of the Facilities Study or the results of the Facilities Study. 9. Results of the Facilities Study shall not be released until arrangements satisfactory to the Transmission Provider have been made for the payment of all costs and expenses referred to in Article 5 above. 10. Connection Applicant acknowledges and agrees that the results of the Facilities Study are estimates only and that actual connection to the Transmission System is subject to the terms and conditions of the Generator Connection Agreement, which agreement must be substantially in the form provided in Attachment J of the Tariff, entered into between the Connection Applicant and the Transmitter. 11. Where any conflict arises between the terms of this Agreement and the Tariff, the provisions of the Tariff shall prevail. 12. This Agreement shall inure to the benefit of and be binding upon the Parties and their respective successors and permitted assigns. 13. This Agreement shall be governed by and construed in accordance with the laws of the Province of New Brunswick. 14. Any notices required under this Agreement must be in writing and shall be made to the appropriate Party s representative as indicated below: Version: 01 Page 3

119 Connection Assessment Procedure In the case of the Transmission Provider: New Brunswick Power Corporation 515 King St. Fredericton, NB E3B 4X1 In the case of the Connection Applicant: IN WITNESS WHEREOF the Parties have caused this Agreement to be executed by their respective authorized officials as of the date first above written. (the Connection Applicant ) NEW BRUNSWICK POWER CORPORATION BY: BY: NAME: NAME: TITLE: TITLE: Version: 01 Page 4

120 Connection Assessment Procedure SCHEDULE A SCHEDULE A SCOPE: Following are the specific tasks and deliverables associated with the Facilities Study to be conducted by NB Power Corporation on behalf of the Connection Applicant. The scope of this study is to provide estimates for following: The design, purchase and installation of all necessary protection and control equipment associated with the transmission line from the wind farm substation(s) to the tap point on the IES. This will include coordination with the protection at the substation site. The design and construction of a transmission line from the wind farm substation to the IES, not including any required Environmental Impact Assessment. The design, purchase, and installation of any required apparatus and associated civil work to connect the transmission line from the wind farm substation to the IES. The design, purchase and installation of the communications facilities that are required for the protection and control equipment as well as to transmit SCADA data associated with the line and protection equipment from the wind farm substations to the NB Power Energy Control Centre (ECC) and the Backup Control Centre (BUCC). This does not include the costs of, or associated with, the required RTU and communications at the wind farm. Version: 01 Page 4

121 SCHEDULE A Connection Assessment Procedure The design, purchase, and installation of the required revenue metering equipment including the communications link to transmit the metered data from the wind farm to the ECC. Study Deliverables The FS report provides detailed estimates of the schedule and costs for the work described in the scope including engineering and design; line routing options; line right-of-way property or easement acquisition; labour; material procurement; project overhead; financial charges, and any other items identified during the study. Version: 01 Page 4

122 ELECTRICITY BUSINESS RULES Appendix C Balanced Schedule Submission

123 Balanced Schedule Submission Appendix C TABLE OF CONTENTS Part 1 Part 2 Part 3 Introduction Process Description Transaction Types Version: 01 Page 1

124 Appendix C Balanced Schedule Submission Part 1 Introduction 1.1 Purpose Appendix C sets out the process by which Transmission Customers will submit, update or withdraw schedules with the SO for the delivery of capacity, energy or ancillary services across the Integrated Electricity System (the IES ). 1.2 Applicability This Appendix is applicable to all Transmission Customers submitting, updating, or withdrawing schedules with the SO for the delivery of capacity, energy or ancillary services across the IES. 1.3 Scheduling Entity Responsibilities It is the responsibility of each Transmission Customer that is scheduling delivery of capacity, energy or ancillary services across the IES to: arrange the appropriate transmission services to support the schedule; submit such schedules electronically; adjust or correct said schedules to reflect updated information; adjust or correct said schedules to reflect SO postings, requests, and directives; respond promptly to any queries from the SO; secure and provide to the SO an export permit for exports from Canada; secure required NERC E-tag and submit it to the SO; secure all other required authorizations; and Version: 01 Page 3 Effecttive Date:: October 1, 2013

125 Appendix C Balanced Schedule Submission all in accordance with the Tariff and the Electricity Business Rules No Transmission Customer shall submit, update or withdraw schedules at the SO for the delivery of capacity, energy or ancillary services across the IES with respect to another Transmission Customer's schedule other than in the role of a Designated Scheduling Agent in accordance with Section No Transmission Customer shall submit, update or withdraw schedules at the SO for the delivery of capacity, energy or ancillary services across the IES with respect to another Transmission Customer's Resource Portfolio other than in the role of a Designated Scheduling Agent in accordance with Sections and 1.5. A Transmission Customer s Resource Portfolio is comprised of those generation facilities directly owned by the Transmission Customer or those generation facilities for which the Transmission Customer has a contract with the generation Facility owner which grant such authority to the Transmission Customer. 1.4 Confidentiality Energy schedules shall be treated as Confidential. 1.5 Designated Scheduling Agent A Transmission Customer may designate a person authorized to act on its behalf in respect of all matters relating to Balanced Schedules, or a defined subset thereof. The SO shall recognize such person as the Transmission Customer s Designated Scheduling Agent provided that the SO receives notice of the designation no less than 5 Business Days and no more than 20 Business Days before the date on which the designation is to take effect. Version: 01 Page 4 Effecttive Date:: October 1, 2013

126 Appendix C Balanced Schedule Submission A Transmission Customer may withdraw the designation of a Designated Scheduling Agent. The SO shall not give effect to such withdrawal unless it receives notification of the withdrawal no less than 5 Business Days and no more than 20 Business Days before the date on which the withdrawal is to take effect While the designation of a Designated Scheduling Agent is in effect, the SO shall use reasonable efforts to communicate with a Transmission Customer's Designated Scheduling Agent in respect of all matters relating to the Transmission Customer s Balanced Schedules, or a defined subset thereof, and any such communication shall be deemed to be communication with the Transmission Customer. The SO reserves the right to communicate directly with the Transmission Customer in respect of the Transmission Customer 's Balanced Schedules, or a defined subset thereof, and any such communication shall be effective notwithstanding that a Designated Scheduling Agent has been appointed by the Transmission Customer The act or omission of a Transmission Customer's Designated Scheduling Agent shall be deemed to be the act or omission of the Transmission Customer. As between the SO and the Transmission Customer, the Transmission Customer shall be bound by and fully liable for all acts or omissions of its Designated Scheduling Agent and shall remain solely responsible and liable to the SO for the due performance of its obligations under the Business Rules. Part 2 Process Description 2.1 Definition of Delivery Points and Points of Receipt Delivery Points are defined by the SO, generally in association with the facility connection process. Delivery Points are generally points of connection on the IES where energy and capacity are injected or withdrawn. In general each Delivery Point corresponds to a connection between a single Facility (including a distribution system) and the IES, or between the IES and an interconnected transmission system. Version: 01 Page 5 Effecttive Date:: October 1, 2013

127 Appendix C Balanced Schedule Submission The SO may define Virtual Delivery Points for either of two purposes: To represent Facilities that are embedded in a distribution system or are embedded in another jurisdiction, or To represent aggregations of sink Delivery Points within New Brunswick, created by the SO at the request of a Transmission Customer for the purpose of submitting Balanced Schedules The SO will make available a table of Delivery Point and Virtual Delivery Point names and definitions that is accessible for use as a menu by Transmission Customers submitting Balanced Schedules References in this Appendix to Delivery Points shall where appropriate include Virtual Delivery Points References in this Appendix to Points of Receipt are to refer to Points-of- Receipt as defined in the Tariff and as listed on the Transmission Provider's OASIS. 2.2 Requirements for Balanced Schedules This section describes the requirements for Balanced Schedules. Certain requirements are reflected in the electronic forms and the automatic validation processes operated by the SO. Other requirements may be subject to off-line validation. Any submission of a Balanced Schedule that does not satisfy the requirements may be rejected Each Balanced Schedule shall be limited to: In respect of a Balanced Schedule for energy, a single 24 hour period from 00:00 to 24:00 Standard or Daylight (whichever is prevailing) as defined by the time zone in which the schedule was submitted (Balanced Schedules for energy may be submitted in the time zone of the Transmission Customer s choice), or In respect of a Balanced Schedule for self-supply of Ancillary Service, a single Dispatch Day, the period 00:00 to 24:00 Atlantic Prevailing Time. Version: 01 Page 6 Effecttive Date:: October 1, 2013

128 Appendix C Balanced Schedule Submission Each Balanced Schedule for energy must comprise, for each scheduling interval, the average number of MW to be injected at each defined Point-of-Receipt and the average number of MW to be withdrawn at each defined Point of Delivery or sink Delivery Point. All MW quantities for energy shall be expressed in integer MW and shall be greater or equal to zero. The total MW injection in each interval of the Balanced Schedule for energy must be equal to the closest integer value to 1 plus the applicable transmission loss factor x the total MW withdrawal in that same interval, with half MW rounded upwards. The associated rounding error shall be settled in accordance with the Tariff and the Business Rules. Zero values must be indicated for all intervals of no scheduled injection or withdrawal Each Balanced Schedule for Ancillary Services must comprise, for each scheduling interval, the number of MW to be presented at each defined Point of Receipt and the number of MW to be available to the system at each defined Point of Delivery or sink Delivery Point. All quantities for ancillary services shall be expressed in multiples of 0.1 MW and shall be greater or equal to zero. Zero values must be indicated for all intervals of no scheduled supply Each transaction that requires a single NERC e-tag shall be submitted as a separate Balanced Schedule Any Balanced Schedule submitted for an export from Canada must include information to identify the export permit under which it is covered. Copies of export permits must be provided in advance to the SO Any Balanced Schedule for a unit contingent export or an export which is intended to be used as a self-supplied Ancillary Service, shall identify the Transmission Customer on behalf of which the Ancillary Service is supplied In the event that the Transmission Customer for a Balanced Schedule has applied to the SO to be permitted to self-supply one or more Ancillary Services in accordance with the Tariff and the Business Rules, and the SO has approved such request accordingly, then: Version: 01 Page 7 Effecttive Date:: October 1, 2013

129 Appendix C Balanced Schedule Submission The Transmission Customer shall include in a Balanced Schedule the Ancillary Services to be provided by each Facility (designated by Point- of- Receipt) in each interval of the Dispatch Day; and The Transmission Customer shall not submit a Balanced Schedule in respect of energy that would be in conflict with the scheduled self-supply of Ancillary Services under that same Balanced Schedule, or under any other concurrent Balanced Schedule submitted by that Transmission Customer In the event that a Balanced Schedule includes the self-supply of an Ancillary Service by a Load Facility, this self-supplied Ancillary Service is required to be included in the relevant list of self-supplied Ancillary Services, and the Point of Receipt Delivery Point ID must reflect the Delivery Point associated with the particular Load Facility (and not a virtual Delivery Point defined for the aggregation of energy withdrawals) Unless appropriately flagged as otherwise in accordance with Part 3, Balanced Schedules for import, export and wheeling transactions will be deemed as firm energy transactions, subject to modification by the SO at the SO's discretion on a nondiscriminatory basis and in accordance with the interconnection agreement with relevant system operators While Transmission Customers are expected to submit Balanced Schedules in respect of their full load forecast, this is not mandated by the Business Rules. It should however be noted that: In the absence of any Balanced Schedule accepted by the SO, all withdrawals by a Transmission Customer will be settled as energy variances under the imbalance provisions of the Tariff, and Transmission Customers may be required to submit revised Balanced Schedules in order to mitigate changes and contingency events. Version: 01 Page 8 Effecttive Date:: October 1, 2013

130 Appendix C Balanced Schedule Submission 2.3 Balanced Schedule Status and Status Indicators Balanced Schedule submissions made via the SO website shall be flagged as new schedules or as revisions. A reference number will be assigned by the SO at the time of the original submission. Revisions shall bear the same identification number as has been assigned to the original submission. Balanced Schedule submissions made by means other than via the SO website shall be flagged as new or as revision in the submission. This is discussed in the state descriptions below New and revised Balanced Schedule submissions are subject to validation to confirm that data entry is complete and appears to conform to requirements. A schedule cannot be submitted until it has completed validation and, when required, must include a NERC e-tag and identification of NEB export permit. Acceptance for inclusion into the scheduling database is automatic until 3:00 p.m. Atlantic Time of the Day Ahead and is discretionary by the SO thereafter. Acceptance does not imply final approval as this will be subject to review against Dispatch Data etc, and (for inter-control-area transactions) check-out When a revised Balanced Schedule is accepted, it replaces the previous submission. Until a revised Balanced Schedule is accepted, both the revision and the previous accepted Balanced Schedule will be retained in the database, and will have separate status indicators. The status comment will indicate whether the Balanced Schedule has passed check-out The following status indicators are used to communicate status of new or revised Balanced Schedules: Empty; the Balanced Schedule has been created and assigned a reference number but the interval MW details have not been submitted. Submitted; new or revised submission passed validation and awaiting review by the SO. Until accepted the submission will not be included in assessments and commitment schedules. Version: 01 Page 9 Effecttive Date:: October 1, 2013

131 Appendix C Balanced Schedule Submission Accepted Pending Review: new or revised submission passed validation and awaiting review by the SO. The submission was accepted automatically for inclusion in assessments and commitment schedules. Accepted; latest submission has been accepted by the SO. The SO has reviewed the submission and verified the e-tag. Rejected; the schedule has been rejected by the SO. Revision rejected; latest submission to revise the schedule has been rejected by the SO. The indicator Revision Rejected will be displayed for a revised submission. Withdrawal Pending; Transmission Customer withdrawal request awaiting review by the SO. Withdrawn; Transmission Customer withdrawal passed validation and accepted automatically or by the SO. Submitted by the SO; new or revised Balanced Schedules submitted by the SO that has passed validation and awaiting review by the SO. Until accepted the submission will not be included in assessments and commitment schedules. Modified by the SO; Balanced Schedule modified from Transmission Customer submission. The status comments will indicate the reason which may be due to check-out failure, a submission on behalf of the Transmission Customer, schedule modified to correct over-committed generation, the schedule has been recalled, etc. Insufficient Transmission Capacity; there is insufficient capacity for the latest submission. In respect of a Point-to-Point schedule this indicates insufficient capacity reserved. In respect of a Network Secondary schedule this indicates insufficient capacity at an interface. In respect of a Network Integration schedule this indicates insufficient designated amount from a designated resources. Version: 01 Page 10 Effecttive Date:: October 1, 2013

132 Appendix C Balanced Schedule Submission 2.4 Submission of New and Revised Balanced Schedules, and the Means to Withdraw a Balanced Schedule Each new Balanced Schedule submitted by a Transmission Customer and accepted by the SO shall be assigned a schedule number by the SO Any Balanced Schedule submitted and accepted by the SO in respect of any given Dispatch Day shall stay in effect unless superseded by a revised Balanced Schedule or withdrawn. Provisional Balanced Schedules automatically become Final Balanced Schedules unless superseded by a revised Balanced Schedule or withdrawn by the appropriate deadlines Any Balanced Schedule submitted by a Transmission Customer and bearing the same schedule number as a previous Balanced Schedule submission shall, on acceptance by the SO, supersede that previous submission In order to effect withdrawal of a Balanced Schedule, a Transmission Customer may in accordance with the timelines permitted by the Tarriff either: submit a revised Balanced Schedule with zero values, or submit a request to have the Balanced Schedule withdrawn Submission of revised Balanced Schedules or withdrawal of Balanced Schedules after 3:00 p.m. Atlantic Time of the Day Ahead (the last Business Day prior to the Dispatch Day) is subject to additional controls including in accordance with the Business Rules: A revised Balanced Schedule must comply with the requirements applicable to all Balanced Schedules; No revised Balanced Schedule may vary from the latest accepted previous submission with respect to any interval that commences sooner, after submission of the revised Balanced Schedule, than permitted by the Tariff; Version: 01 Page 11 Effecttive Date:: October 1, 2013

133 Appendix C Balanced Schedule Submission The SO may reject revised or new Balanced Schedules due to insufficient time for assessment of the impact of material changes in accordance with section below; To the extent that the SO has included in a Final Day Ahead Commitment Schedule, or any later Commitment Schedule, the provision of Ancillary Services from a Generation Facility, no revised Balanced Schedule should seek to schedule additional energy output from that Generation Facility that would reduce its capability of providing the scheduled Ancillary Services; The SO may reject new or revised Balanced Schedules that are rejected by other affected system operators; The SO may reject revised Balanced Schedules if the IES is not in a normal operating state, if the SO is not satisfied that acceptance would not threaten reliability of the IES or any Zone thereof, or if insufficient time remains for the SO s assessment in accordance with section below; and A request to withdraw a Balanced Schedule may not be submitted later than permitted by the Tariff. A request for withdrawal submitted after 3:00 p.m. Atlantic Time of the Day Ahead is subject to the same controls as a revised Balanced Schedule When the SO receives valid submission of a new or revised Balanced Schedule, or a request to withdraw a Balanced Schedule, it shall use its reasonable best efforts to complete assessments in a timely manner, and in sufficient time to allow inclusion of the submission in the Final Balanced Schedule. The level of such reasonable best efforts shall take account of workload in managing grid conditions, staff availability etc. 2.5 Timing of Balanced Schedule Submissions Version: 01 Page 12 Effecttive Date:: October 1, 2013

134 Appendix C Balanced Schedule Submission A Balanced Schedule in respect of a given Dispatch Day may first be submitted as a Provisional Balanced Schedule at any time after 00:01 on the 45th day prior to the Dispatch Day Deadlines for the submission of new or revised Balanced Schedules are defined in the Tariff and the Business Rules, Chapter Form of Submission of Balanced Schedules Except as noted in section below, Balanced Schedules are to be submitted electronically using the web-based form or an equivalent file upload protocol acceptable to the SO The form to be used for fax transmission in case of system delays or failures will be provided by the SO upon request. 2.7 Validation of Balanced Schedules An on-line automatic validation is carried out on data entry into a field. The presubmission validation is initiated by the attempted submission of a form, and is carried out before the upload into the database that constitutes submission Submissions validated on line, and made before 3:00 p.m. Atlantic Time of the Day Ahead are automatically accepted by the SO, subject to check-out and to review in accordance with section below Note that the acceptance by the SO of a Balanced Schedule does not imply that the submission of such a Balanced Schedule is in accordance with, or in any way satisfies, a Transmission Customer s obligations under the Business Rules If submission is after 3:00 p.m. Atlantic Time of the Day Ahead, the submission will be subject after submission to review by the SO against the criteria set out in the third and fourth bullets of section above. Only when the SO has completed such review as it Version: 01 Page 13 Effecttive Date:: October 1, 2013

135 Appendix C Balanced Schedule Submission sees fit and in accordance with section above, will a Balanced Schedule submission be accepted and may still be subject to additional check-out In its use of Balanced Schedules, after their acceptance, the SO will check for compatibility with Dispatch Data and Generation Facility capabilities. If the SO identifies discrepancies, it shall notify the Transmission Customer NERC e-tag data, in accordance with NERC policy, must be included in the schedule submission A Balanced Schedule will fail validation if the Balanced Schedule submission is incomplete with respect to e-tag data A Balanced Schedule may be rejected if its implementation would materially impair system reliability during ramping-in or ramping-out of the transaction. 2.8 Changes by the SO If the SO has identified a problem in accordance with section 2.7.4, and the SO has not accepted a revised Balanced Schedule that resolves the problem, the SO may adjust one or more Balanced Schedules. Such changes shall have effect for operations and for settlement purposes The SO may revise any Balanced Schedule at any time in order to give effect to Transmission Loading Relief in accordance with NERC practices, or in recognition of Control Actions taken in accordance with the EBR. Such changes shall have effect for operations and for settlement purposes The SO shall change Balanced Schedule energy flows in respect of changes made in nonfirm schedules in accordance with section above. Such changes shall have effect for operations and for settlement purposes. Version: 01 Page 14 Effecttive Date:: October 1, 2013

136 Appendix C Balanced Schedule Submission Notification of status changes or modifications by the SO will be communicated by provided the Transmission Customer has provided a notification address. Otherwise all status changes or modifications will be indicated on the SO website Posting of Balanced Schedule Information Each Balanced Schedule that has been submitted will be website accessible to the Transmission Customer that submitted it for inspection. Status information (submitted, accepted, modified by the SO, rejected) will be indicated in addition to the submitted information. The Transmission Customer will be able to download an existing Balanced Schedule as a basis for revision and re-submission. Part 3 Transaction Types The SO will accommodate the scheduling and delivery of transactions of various types at the request of Transmission Customers provided such accommodation is not in conflict with the Tariff, is non-discriminatory, follows good utility practice, and does not compromise reliability. Such transactions may include, but will not be limited to, Transmission Customer transactions of scheduled energy, generation capacity, dispatchable energy, and ancillary services, as well as system operator to system operator arrangements for reliability programs. Version: 01 Page 15 Effecttive Date:: October 1, 2013

137 ELECTRICITY BUSINESS RULES Appendix D Third Party Generator Dispatch Data Submission

138 Third Party Generator Dispatch Data Submission Appendix D TABLE OF CONTENTS Part 1 Introduction 1.1 Purpose of Dispatch Data 1.2 Applicability Part 2 Dispatch Data Requirements and Procedure 2.1 Quantities 2.2 Static and Dynamic Dispatch Data 2.3 Requirements for Dispatch Data for Non-Dispatchable Variable Generators (NDVG) 2.4 Dispatch Data Status and Status Indicators 2.5 Submission of Dispatch Data and Revisions to Dispatch Data 2.6 SO Validation of Dispatch Data 2.7 Revision and Withdrawal of Dispatch Data 2.8 Posting of Dispatch Data Information 2.9 Publication Version No: 01 Page 2 Effective Date: october 1, 2013

139 Third Party Generator Dispatch Data Submission Appendix D Part 1 Introduction 1.1 Purpose of Dispatch Data This Appendix reflects an interim approach to dispatch data in which price quantity pairs are used to indicate generation costs. A future change to use cost per data is anticipated pending a change of the dispatch system. The purpose of this Appendix is to define the process, documents and forms to be used in relation to the submission and modification of Dispatch Data by Transmission Users who own and schedule a Third Party Generation Facility and the treatment by the SO of Dispatch Data submissions. Dispatch Data comprises the price and cost information submitted to the SO by the Transmission Users and accepted by the SO, for the use by the SO in settlement with Third Party Generation Facilities in instances when the SO issues a Re-dispatch instruction or Must-Run designation. Re-Dispatch and Must-Run instructions will only be given by the SO after all other resources of the Corporation have been completely dispatched. Note that Dispatch Data submissions do not become Dispatch Data until accepted by the SO. Note that Dispatch Data is not intended to define the physical operating capabilities and limits of generation facilities. These capabilities and limits are provided to the SO prior to Facility connection and in Outage planning and notification. Dispatch Data should however respect the capabilities and limits of Facilities. 1.2 Applicability As described above, and for greater certainty in accordance with the Business Rules section 3.3.3, the submission and modification of Dispatch Data is the responsibility of any Transmission User who owns a Third Party generation facility. Generally, this will Version No: 01 Page 3 Effective Date: october 1, 2013

140 Third Party Generator Dispatch Data Submission Appendix D include incremental cost estimates including start-up, minimum run costs and incremental production costs for use by the SO in Re-dispatch or Must-Run of such Generating Facilities. To the extent it deems necessary the SO may request additional information, supporting data or audit data submitted at any time within a year of the Re-dispatch event to which it applies. The Transmission User shall promptly submit any additional information and or data thus requested, and shall assist the SO in any review or audit. Part 2 Dispatch Data Requirements and Procedure 2.1 Quantities All references to energy quantities in this Appendix D refer to the MWh injected into the IES at the relevant Delivery Point in any clock hour. 2.2 Static and Dynamic Dispatch Data Dispatch Data comprises static Dispatch Data and dynamic Dispatch Data. Standing Dispatch Data includes static Dispatch Data and any dynamic Dispatch Data that is carried over from one day to the next Static Dispatch Data is the portion of Dispatch Data that is subject to occasional change only, and is generally dependent on physical characteristics of each Facility or is strictly cost based. Static Dispatch Data shall include, but not be limited to, the following: a) start-up costs, expressed in $/start, which would typically comprise the following costs only as they relate to the final two hours immediately prior to synchronization: i) ignition fuel and main fuel costs to bring the Facility from its expected condition two hours prior to synchronization to the condition in which it is ready to be synchronized to the SO-controlled Grid, ii) Cost of electricity required to start up the Facility, iii) Variable O&M costs associated with Facility start-up. Version No: 01 Page 4 Effective Date: october 1, 2013

141 Third Party Generator Dispatch Data Submission Appendix D Such costs specifically exclude all contributions to fixed costs and profit. b) Minimum Run Quantity (MRQ), which shall be the lowest level of output for stable operation of the Generation Facility at the system and ambient conditions then expected to prevail. The MRQ shall generally correspond to the information provided in the Facility registration data unless due to particular changed circumstances. c) Minimum Run Time (MRT), which shall be the normal minimum period of operation at no less than the MRQ in order to avoid undue stress and damage to equipment. d) Minimum Run Cost (MRC), which is the cost of operating at MRQ, comprising only fuel cost and variable O&M cost Dynamic Dispatch Data is the portion of Dispatch Data that relates to the marginal operation of Facilities, and may be modified on a dynamic basis. Dynamic Dispatch Data shall include, but not be limited to, the following: For each hour of the day, from one to ten P/Q Pairs, such that Price P(1) is the incremental price in $ / MWh for each MWh of injection to the SO-controlled Grid in excess of the MRQ but less than or equal to Q(1), in the relevant clock hour. Price P(n) is the incremental price in $ / MWh for each MWh of injection to the SO-controlled Grid in excess of Q(n-1) but less than or equal to Q(n), in the relevant clock hour The following constraints apply: MRQ < Q(1) < Q(2) < < Q(n -1) < Q(n ), where Q(n ) is the rated max max max MW output of the Generation Facility. $0 < P(1) < P(2) <. < P(n -1) < P(n ) $1,000 max max Q(n) shall be stated in MW integer values. P(n) shall be stated in $ to two places of decimals Version No: 01 Page 5 Effective Date: october 1, 2013

142 Third Party Generator Dispatch Data Submission Appendix D Static Dispatch Data shall have the form of standing data, valid for all hours of every day until revised. Dynamic Dispatch Data will be viewed as a 24 hour strip of data to be carried over to the next day in the absence of any new Dispatch Data for that next day. 2.3 Requirements for Dispatch Data for Non-Dispatchable Variable Generators (NDVG) The Static Dispatch Data required for an NDVG is the as follows: Start-up costs = $0 Minimum Run Quantity (MRQ) = 0 MW Minimum Run Time (MRT) = 0 hours The Dynamic Dispatch Data required for an NDVG is as follows: Only one P/Q Pair, with P(1) = $0/MWh and Q(1) = rated MW output A Transmission User for an NDVG may, through its connection of such a Facility, elect the means by which the Dispatch Instruction will be updated as one of the following: (i) calculating the total MW output from the Final Hourly Balanced Schedules associated with the Facility, (ii) automated forecasting of the MW output by the SO based on telemetry data via the SO s SCADA system in respect of variable factors that affect production. 2.4 Dispatch Data Status and Status Indicators In view of the carry-forward provisions with respect to Dispatch Data, substantially all Dispatch Data submissions are in effect revisions Dispatch Data submissions are subject to: Version No: 01 Page 6 Effective Date: october 1, 2013

143 Third Party Generator Dispatch Data Submission Appendix D Validation to confirm that data entry is complete and conforms to requirements. Dispatch data cannot be submitted until it has completed validation. Acceptance for inclusion in the dispatch database. Acceptance is automatic until 11:00 a.m. Atlantic Time of the Day Ahead. Acceptance does not imply acceptance that Dispatch Data satisfy, or are not in conflict with, a Transmission User s obligations under the Business Rules When Dispatch Data is accepted in respect of a given Dispatch Day, it replaces the previous submission The following status indicators are used to communicate status of a Dispatch Data submission: Submitted: submission passed validation and awaiting review by the SO. Previous accepted Dispatch Data remains in effect. Submitted by SO: used if the SO enters Dispatch Data on behalf of a Transmission User; the data has not yet been accepted. Accepted: submission passed validation and accepted automatically or by SO Rejected: submission rejected; previous accepted Dispatch Data remains in effect. Modified by SO: used if the SO enters or corrects Dispatch Data on behalf of a Transmission User; the data has been accepted automatically by the SO. Standing Data: displayed whenever the accepted Dispatch Data has been carried ahead from a previous date. In order to remove a Dispatch Data submission, the Transmission User will be required to re-submit zero values. The Dispatch Data for a Facility that is on a Forced Outage or Version No: 01 Page 7 Effective Date: october 1, 2013

144 Third Party Generator Dispatch Data Submission Appendix D Planned Outage state does not have to be removed; however, when the Facility becomes available for dispatch by the SO the standing Dispatch Data will be used. 2.5 Submission of Dispatch Data and Revisions to Dispatch Data Dispatch Data shall be submitted electronically to the SO website Dispatch Data in respect of any Dispatch Day shall be submitted no later than 11:00 a.m. Atlantic Time of the Day Ahead. In the event that the SO has received no valid static Dispatch Data by 11:00 a.m. Atlantic Time on the Day Ahead, then the latest previous valid static Dispatch Data shall be brought forward A Transmission User may submit revised Dispatch Data prior to 3:00 p.m. Atlantic Time on the Day Ahead, and such revised Dispatch Data shall, if any price or quantity is revised by more than 10%, be subject to review and acceptance or rejection by the SO Dispatch Data is required to be a genuine pre-estimate of actual costs and equipment capabilities. The SO may therefore require that a Transmission User provide substantiation of Dispatch Data in respect of any period. Any such Transmission User shall promptly provide such substantiation, and shall resolve any queries to the reasonable satisfaction of the SO Only one set of Dispatch Data may exist for any Facility at any one time. The acceptance by the SO of any Dispatch Data for a Facility automatically results in the replacement of the old set by the new set A Transmission User for a Third Party Generation Facility may at any time submit to the SO revisions to its Dispatch Data for hours commencing more than 1 full clock hour after the submission of such revisions. The SO shall approve such requests unless the SO determines that such a change would threaten the Reliability of the IES. Version No: 01 Page 8 Effective Date: october 1, 2013

145 Third Party Generator Dispatch Data Submission Appendix D 2.6 SO Validation of Dispatch Data The on-line automatic validation of Dispatch Data will be performed as described below. This on-line validation may be carried out on data entry into a field or as part of the presubmission validation. The pre-submission validation is initiated by the attempted submission of a form, and is carried out before the submission will be permitted. View next page for Validation and Description of Static Dispatch Data Fields Version No: 01 Page 9 Effective Date: october 1, 2013

146 Third Party Generator Dispatch Data Submission Appendix D Validation and Description of Static Dispatch Data Fields Thermal and Other Facilities Field Description and Validation Required/ Optional Effective Date/Hour Unit Min Run Cost Startup Cost Min Run Quantity Min Run Hours Comments Notification Used to select date/hour for which static dispatch data is to be R submitted. The entered date/hour will be validated to ensure it is a valid date/time in prevailing Atlantic time. A submission will not be effective for current or past hours, and valid submission times are limited to today and the next five days. Used to select the unit for which static dispatch data is to be R submitted. The selected unit is validated to ensure that the submitting Market Participant has appropriate rights to be able to submit data for the unit. This field is used to input the minimum run cost in Canadian R dollars. Validation requires that it be a numeric, non-negative value. This field is used to input the startup cost in Canadian dollars. R Validation requires that it be a numeric, non-negative value. This field is used to input the minimum run quantity in net MW. R Validation requires that it be a numeric, non-negative value and be within the physical capability of the unit. This field is used to input the minimum run hours. Validation R requires that it be a numeric, non-negative value. This field allows the market participant to enter comments with O the submission. This field allows the market participant to indicate the O address that will be used to notify them of any submission status changes. Version No: 01 Page 10 Effective Date: october 1, 2013

147 Third Party Generator Dispatch Data Submission Appendix D Submit This button is used to submit the data. If the data passes presubmission validation then it is stored in the database and the market participant is notified of the status. If validation fails, the market participant is informed of the error(s) that caused the validation to fail, and will be allowed to correct and re-submit the data. N/A Validation and Description of Static Dispatch Data Fields Thermal and Other Facilities Field Description and Validation Required /Optionsl Date Facility Comments Notification Used to select date for which dynamic dispatch data is to be submitted. The entered date will be validated to ensure it is a valid date. A submission will not be effective for past hours, and valid submission dates are limited to today and the next five days. Used to select the facility for which dynamic dispatch data is to be submitted. The selected facility is validated to ensure that the Transmission User has appropriate rights to be able to submit data for the facility. This field allows the Transmission User to enter comments with the submission. This field allows the Transmission User to indicate the address tht will be used to notify them of any submission status changes. R O O Version No: 01 Page 11 Effective Date: october 1, 2013

148 Third Party Generator Dispatch Data Submission Appendix D P(n) Q(n) Submit These fields allow the Transmission User to enter the price portion of up to ten price/quantity pairs per hour. The price is in Canadian dollars. Validation requires that: at least one price/quantity pair per hour be entered. Zeroes may be entered for both price and quantity to remove all dynamic dispatch data for the hour. each non-zero price entered must have a corresponding non-zero quantity (Q) P(n) > P(n-1) <= P(n) <= 2000 These fields allow the Transmission User to enter the quantity portion of up to ten price/quantity pairs per hour. The quanity is in net MWh. Validation requires that: at least one price/quantity pair per hour be entered. Zeroes may be entered for both price and quantity to remove all dynamic dispatch data for the hour. Q(1) > Minimum Run Quantity Q(n) > Q(n-1) Q(n) <= Rated Maximum This button is used to submit the data. If the data passes presubmission validation then it is stored in the database and the Transmission User is notified of the status. If validation fails, the market participant is informed of the error(s) that caused the validation to fail, and will be allowed to correct and re-submit the data. R R N/A Version No: 01 Page 12 Effective Date: october 1, 2013

149 Third Party Generator Dispatch Data Submission Appendix D Validation and Description of Static Dispatch Data Fields Hydraulic Facilities Field Description and Validation Required/ Optional Effective Date/Hour Unit Min Run Quantity Comments Notification Submit Used to select date/hour for which static dispatch data is to be submitted. The entered date/hour will be validated to ensure it is a valid date/time in prevailing Atlantic Time. A submission will not be effective for current or past hours, and valid submission times are limited to today and the next five days. Used to select the unit for which static dispatch data is to be submitted. The selected unit is validated to ensure that the submitting Transmission User has appropriate right to be able to submit data for the unit. This field is used to input the minimum run quantity in net MW. Validation requires that it be a numeric, non-negative value and be within the physical capability of the unit. This field allows the market particpantto enter comments with the submission. This field allows the market participant to indicate the address that will be used to notify them of any submission sttus changes. This button is used to submit the data. If the date passes presubmission validation then it is stored in the data base and the Transmission User is notified of the status. If validation fails, the market participant is informed of the error(s) that caused the validation to fail, and will be allowed to correct and re-submit the data. R R R O O N/A Version No: 01 Page 13 Effective Date: october 1, 2013

150 Third Party Generator Dispatch Data Submission Appendix D Validation and Description of Static Dispatch Data Fields Hydraulic Facilities Field Description and Validation Required/ Optional Date Facility Comments Notification P(n) Used to select date for which dynamic dispatch data is to be submitted. The entered date will be validated to ensure it is a valid date. A submission will not be effective for past hours, and valid submission dates are limited to today and the next five days. Used to select the facility for which dynamic dispatch data is to be submitted. Thye selected facility is validated to ensure that the Transmission User has appropriate rights to be able to sumbit data for facility. This field allows the Transmission User to enter comments with the submission. This field allows the Transmission User to indicate the address that will be used to notify them of any submission status changes. These fields allow the market participant to enter the price portion of up to ten price/quantity pairs per hour. The price is in Canadian dollars. Validation requires that: at least one price/quantity pair per hour be entered. Zeroes may be entered for both price and quantity to remove all dynamic dispatch data for the hour. each non-zero price entered must have a corresponding non-zero quantity (Q) P(1) <= 0 P(n) > P(n-1) <= P(n) <= 2000 R R O O R Version No: 01 Page 14 Effective Date: october 1, 2013

151 Third Party Generator Dispatch Data Submission Appendix D Q(n) Submit These fields allow the Transmission User to enter the quantity portion of up to ten price/quantity pairs per hour. The quantity is in net MWh. Validation requires that: at least one price/quantity pair per hour be entered. Zeroes may be entered for both price and quantity to remove all dynamic dispatch data for the hour. Q(1) > Minimum Run Quantity Q(n) > Q(n-1) Q(n) <= Rated Maximum This button is used to submit the data. If the data passes presubmission validation then it is stored in the database and the Transmission User is notified of the status. If validation fails, the market participant is informed of the error(s) that caused the validation to fail, and will be allowed to correct and re-submit the data. R N/A Submissions validated on line, and made before 11:00 a.m. Atlantic Time of the Day Ahead are accepted automatically. Validated submissions before 3:00 p.m. Atlantic Time of the Day Ahead and that do not change relevant parameters by more than 10% are also accepted automatically Note that the acceptance by the SO of Dispatch Data does not imply that the submission of such a Dispatch Data is in accordance with, or in any way satisfies, a Transmission User s obligations under the Business Rules In the event submission is after 3:00 p.m. Atlantic Time of the Day Ahead, the submission will be subject to review by the SO before acceptance. Acceptance will only be granted in exceptional circumstances In accordance with section of the Business Rules the SO may request additional supporting data and may review or audit data submitted under this section at any time within a year of the Re-dispatch event to which it applies. Version No: 01 Page 15 Effective Date: october 1, 2013

152 Third Party Generator Dispatch Data Submission Appendix D 2.7 Revision and Withdrawal of Dispatch Data Only the Transmission User submitting Dispatch Data may revise it or withdraw it Revision of Dispatch Data is effected by submission of a revised set of Dispatch Data, and the SO s acceptance of such revised Dispatch Data Withdrawal of dynamic Dispatch Data is affected by submission and discretionary acceptance by the SO of a revised set of dynamic Dispatch Data with zero values Revision of Dispatch Data will be in accordance with section of the Business Rules. 2.8 Posting of Dispatch Data Information Dispatch Data that has been submitted and accepted, but not superseded or withdrawn, will be web-site accessible to the Transmission User that submitted it, for inspection, and downloading. The final Dispatch Data in effect for each day shall continue to be available until the end of the month after the month of the Dispatch Day. 2.9 Publication The SO publishes no information on individual Dispatch Data. Version No: 01 Page 16 Effective Date: october 1, 2013

153 ELECTRICITY BUSINESS RULES Appendix E Ancillary Services Operational Requirements

154 Ancillary Services Operational Requirements Appendix E TABLE OF CONTENTS Part 1 Introduction 1.1 Background 1.2 Purpose 1.3 Scope and Application Part 2 Provision of Ancillary Services and Recordkeeping 2.1 Common Operating Procedure 2.3 Scheduling 2.4 Activation 2.5 AS Provider Response 2.6 Black Start 2.7 Performance Standards 2.8 Performance Requirements 2.9 Notice of Unavailability of Service 2.10 Changes to AS Provider Facilities 2.11 Recordkeeping 2.12 Retention Period Part 3 Maintenance and Testing 3.1 Maintenance 3.2 Testing 3.3 Additional Testing 3.4 AS Provider Notice and SO Attendance 3.5 Reporting Results 3.6 AS Provider Testing 3.7 Failure to Test 3.8 Deficiency Period 3.9 Exception 3.10 Cost of Testing 3.11 Exception Version: 01 Page 2 Effective Date: October 11, 2013

155 Ancillary Services Operational Requirements Appendix E Part 4 Remedial Measures 4.1 Obligation to Take Remedial Measures 4.2 No Scheduling 4.3 Scheduling to Reduced Capability ATTACHMENT 1 ATTACHMENT 2 ATTACHMENT 3 ATTACHMENT 4 ATTACHMENT 5 AS FACILITIES SPECIFIC INFORMATION REACTIVE POWER/VOLTAGE SUPPORT SERVICE AUTOMATIC GENERATION CONTROL SERVICE AND LOAD FOLLOWING SERVICE OPERATING RESERVE BLACK START CAPABILITY SERVICE Version: 01 Page 3 Effective Date: October 11, 2013

156 Ancillary Services Operational Requirements Appendix E PART 1 INTRODUCTION 1.1 Background: To ensure the reliable operation of the Integrated Electricity System, those Facilities in NB and in the case of Capacity Based Ancillary Services, the NB Balancing Area, seeking to provide Ancillary Services (AS Provider) must meet the necessary operational requirements. These requirements enable the SO to account for and activate the necessary Ancillary Services as may be required for system conditions to ensure the reliable operation of the Integrated Electricity System. 1.2 Purpose: To provide the following: a) a potential or existing AS Provider the necessary operational requirements to qualify as a provider of an Ancillary Service; and b) to the SO, the AS Provider s capabilities for the purpose of planning, activation, testing and monitoring of the particular Ancillary Service. 1.3 Scope and Application: With the exception of Reactive Supply and Voltage Control Service, these operational requirements are applicable to all AS Providers in the NB Balancing Area. Reactive Supply and Voltage Control Service can only be provided by those synchronous generators in NB qualified to provide this service in accordance with these requirements. AS Providers external to NB, but within the NB Balancing Area may be subject to the associated Interconnection Agreements between the AS Provider s local control center and the SO. AS Providers external to NB may also be subject to those provisions in the Tariff Generation Connection Agreement that are applicable to the particular Ancillary Service the Facility is seeking to provide. Version: 01 Page 4 Effective Date: October 11, 2013

157 Ancillary Services Operational Requirements Appendix E PART 2 PROVISION OF ANCILLARY SERVICES 2.1 Operating Procedure(s): The SO may require an operating procedure with the AS Provider for the purpose of the planning, activation, testing and monitoring of the particular Ancillary Service. 2.2 This section is not used. 2.3 Scheduling: Subject to section 2.6, the SO may (but shall not be obliged to) at any time and from time to time, issue a schedule or Dispatch Instructions to the AS Provider calling for the provision of the Ancillary Service. Any such schedule or Dispatch Instructions shall be issued in accordance with the Electricity Business Rules and using such communications protocols as may be specified in Table 1 or applicable operating procedure in section Activation: Where the Ancillary Services include one or more of Regulation Service, Load Following Service or Operating Reserve Service, the SO may (but shall not be obliged to) at any time and from time to time issue control instructions or Dispatch Instructions to the AS Provider calling for the provision of energy. 2.5 AS Provider Response: Subject to section 2.6, the AS Provider shall comply, and shall ensure that the AS Provider Facilities comply, with a schedule, Dispatch Instructions or control instructions issued under section 2.3 or Black Start: The following apply to the provision of Black Start Capability Service in lieu of sections 2.3 and 2.5: Version: 01 Page 5 Effective Date: October 11, 2013

158 Ancillary Services Operational Requirements Appendix E a) the SO may issue instructions to the AS Provider to provide Black Start Capability Service in the circumstances and manner specified in the Integrated Electricity System restoration plan; and b) the AS Provider shall use all reasonable endeavors consistent with Good Utility Practice to ensure that the Facilities comply with such instructions. 2.7 Performance Standards: The AS Provider shall provide each Ancillary Service in accordance with the Performance Standards for the Ancillary Service as specified in Part I of the applicable Appendix E Attachment. 2.8 Performance Requirements: The AS Provider shall ensure that the Facilities used to provide an Ancillary Service are maintained and operated in such a manner as to enable them to meet the performance requirements for that Ancillary Service as specified in Attachment 1. The AS Provider shall also ensure that the AS Facilities comply with all applicable technical requirements of the Electricity Business Rules, including the applicable Reliability Requirements pertaining to communications and to operational reporting and monitoring referred to in Chapter 3 of the Electricity Business Rules. 2.9 Notice of Unavailability of Service: The AS Provider shall promptly notify the SO: a) if the AS Provider considers that the Facilities used to provide an Ancillary Service are or will become incapable of meeting the performance requirements for that Ancillary Service or of providing the Ancillary Service in accordance with the Performance Standards for that Ancillary Service; or b) of the failure or inability of the AS Provider or the Facilities to comply with a schedule, Dispatch Instruction, control instruction or instruction issued to the AS Provider under section 2.3, 2.4 or 2.6(a). Such notice shall indicate the nature and cause of the existing or forecasted unavailability and its expected duration. The SO shall promptly notify the AS Provider in Version: 01 Page 6 Effective Date: October 11, 2013

159 Ancillary Services Operational Requirements Appendix E the event that there has been a deficiency in the provision of a Ancillary Service, that there has been a failure to comply with a schedule, Dispatch Instruction, control instruction or instruction issued to the AS Provider under section 2.3, 2.4 or 2.6(a) or that the Ancillary Service has been provided other than in accordance with the Performance Standards for that Ancillary Service Changes to AS Provider Facilities: The AS Provider shall promptly notify the SO if a change or modification to any of the Facilities has been or will be made in a manner that could reasonably be expected to affect the ability of the Facilities to be capable of meeting the Performance Requirements for an Ancillary Service or of providing an Ancillary Service in accordance with the Performance Standards for that Ancillary Service Recordkeeping: The AS Provider shall maintain accurate and complete Records in written or electronic form relating to the provision of each Ancillary Service provided including records: a) of the procedures used in conducting, and the results of, any tests conducted under Part 3 or section 4.1; b) of the periods in which the AS Facilities are not capable of providing the Ancillary Service; c) of any maintenance performed on the AS Facilities; d) of the results of any in service performance monitoring required under the Electricity Business Rules or in any applicable Performance Requirements; and e) of any notifications transmitted to or received from the SO for the supply of Ancillary Services other than electronic commands received from the SO that activate the Ancillary Service(s). Version: 01 Page 7 Effective Date: October 11, 2013

160 Ancillary Services Operational Requirements Appendix E 2.12 Retention Period: A Record referred to in section 2.11 shall be retained by the AS Provider for a period that is no less than seven years from the date on which the Record was created or received by the AS Provider. PART 3 MAINTENANCE AND TESTING 3.1 Maintenance: An AS Provider shall maintain its Facility in accordance with Good Utility Practice and shall comply with all applicable provisions of Chapter 3 of the Electricity Business Rules pertaining to the notification, scheduling and coordination of Outages pertaining to the Facility. 3.2 Testing: The AS Provider shall, in respect of each Ancillary Service that it is providing, conduct the tests described in Part II of the applicable Attachment. Such tests shall be conducted at the time and in the manner specified in such applicable Attachment or, in the absence of such detail, at such time and in such manner as may be agreed between the AS Provider and the SO. Failing such agreement, they must be conducted at the time and in the manner specified by the SO. 3.3 Additional Testing: Where the SO believes on reasonable grounds that the AS Facilities are incapable of meeting the performance requirements for an Ancillary Service or of providing an Ancillary Service in accordance with the performance standards for that Ancillary Service, the SO may require that the AS Provider conduct: a) one or more of the tests described in Part II of the applicable Attachment; and/or b) such other tests as the SO may reasonably require. Such testing may be required notwithstanding any limitation contained in Part II of the applicable Attachment as to the number of tests that may be required. Without limiting the generality of the foregoing, the SO may require such testing where notice of Version: 01 Page 8 Effective Date: October 11, 2013

161 Ancillary Services Operational Requirements Appendix E unavailability has been given under section 2.9, where notice of a change or modification has been given under section 2.10 or where the AS Facilities have failed a test. Tests required under this section 3.3 shall be conducted at such time and in such manner as may be agreed between the parties, failing which agreement they shall be conducted at the time and in the manner specified by the SO. 3.4 AS Provider Notice and SO Attendance: The AS Provider shall give the SO reasonable notice of the date and time of any test to be conducted under section 3.2 or 3.3. The SO is entitled to have its representative(s) attend at and witness the test. If the SO gives notice to the AS Provider of its intention to witness a test the AS Provider shall provide sufficient access to permit the SO's representative(s) to witness the test in order to verify that the test is correctly carried out. 3.5 Reporting Results: The AS Provider shall provide the SO with evidence that a test required under section 3.2 or 3.3 has been conducted and with written results of the test within ten (10) Business Days of the completion of the test. 3.6 AS Provider Testing: Nothing in sections 3.2 and 3.3 shall be construed as limiting the right of the AS Provider to conduct any other tests at any time during the term of the Ancillary Service provided. Such other tests shall be scheduled with the SO and shall comply with all applicable provisions of Chapter 3 of the Electricity Business Rules pertaining to the notification, scheduling and coordination of Outages pertaining to the Facilities. 3.7 Failure to Test: Where the AS Provider fails to conduct a test required by section 3.2, 3.3 or 4.1; the SO may request an explanation as to why the test was not carried out. The AS Provider shall provide such an explanation within two (2) Business Days of receipt of the SO's request, together with an indication of when the test will be conducted. The SO may also request that the AS Provider provide evidence satisfactory to the SO that the AS Facilities meet the performance requirements specified in Attachment 1 for such Ancillary Service and are capable of providing the Ancillary Version: 01 Page 9 Effective Date: October 11, 2013

162 Ancillary Services Operational Requirements Appendix E Service in accordance with the applicable performance standards. If evidence satisfactory to the SO is not so provided, the failure to conduct the test shall be deemed to be the failure of such test and section 3.8 shall apply. 3.8 Deficiency Period: Subject to section 3.9, where section 3.7 applies or where a test conducted in accordance with this Appendix fails to demonstrate that the AS Facilities meet the performance requirements set forth in Attachment 1, the AS Facilities shall be deemed to be incapable of providing the Ancillary Service in accordance with the applicable performance standards for the period: a) commencing half way between: i. the date of the test or, where section 3.7 applies, the date of the request for evidence made by the SO under that section; ii. the most recent to occur of: A. the last time a test was conducted that demonstrated that the AS Facilities met the applicable performance requirements; B. the last time the Ancillary Service was successfully provided to the SO using the AS Facilities in accordance with all performance standards and performance requirements applicable to that Ancillary Service; and C. the date of the commencement of the applicable Ancillary Service from the AS Facility; and b) concluding on the date that the AS Provider demonstrates to the satisfaction of the SO that the AS Facilities meet the performance requirements for the applicable Ancillary Service. Version: 01 Page 10 Effective Date: October 11, 2013

163 Ancillary Services Operational Requirements Appendix E 3.9 Exception: Where the AS Provider can demonstrate to the satisfaction of the SO, or the SO can demonstrate, that the AS Facilities commenced to fail to meet the performance requirements set forth in Attachment 1 on a specified date, that date shall be the date on which the AS Facilities are deemed to have commenced to be incapable of providing the Ancillary Service in accordance with the applicable performance standards Cost of Testing: Subject to section 3.11, each of the SO and the AS Provider shall bear their own costs and expenses relating to the conducting of tests under these requirements Exception: The AS Provider shall pay for the SO's reasonable costs and expenses in conducting and reviewing the results of any test: a) conducted under section 3.2 or 3.3 that fails to demonstrate that the AS Facilities meet the applicable performance requirements or the applicable performance standards in a material respect; or b) conducted under section 4.1. PART 4 REMEDIAL MEASURES 4.1 Obligation to Take Remedial Measures: Where: a) the AS Facilities are deemed to be incapable of providing an Ancillary Service under section 3.8; b) the AS Provider or the SO has given notice under section 2.9; or c) the SO has made a request under section 3.7; the AS Provider shall promptly take such remedial measures as may be required to ensure that the AS Facilities meet all applicable performance requirements and can provide the Ancillary Service in accordance with the applicable performance standards. Version: 01 Page 11 Effective Date: October 11, 2013

164 Ancillary Services Operational Requirements Appendix E The AS Provider shall notify the SO of the remedial measures and shall keep the SO apprised of the status and progress of their implementation. The AS Provider shall conduct such additional tests and provide the SO with such evidence satisfactory to the SO as the SO may require in order for the SO to determine that the AS Facilities can meet all applicable performance requirements and provide the Ancillary Service in accordance with the applicable performance standards. Section 3.4 shall apply to any test conducted under this section No Scheduling: Subject to section 4.3, where: a) the AS Facilities are deemed to be incapable of providing an Ancillary Service under section 3.8; b) the AS Provider or the SO has given notice under section 2.9; or c) the SO has made a request under section 3.7, the SO shall not issue a schedule, Dispatch Instructions or control instructions referred to in section 2.3 or 2.4 in respect of the applicable Ancillary Service until such time as the SO is satisfied that the AS Facilities meet the performance requirements for that Ancillary Service and are capable of providing the Ancillary Service in accordance with the applicable performance standards. 4.3 Scheduling to Reduced Capability: Where one or more of sections 4.2(a) to 4.2(c) apply and the SO considers that the AS Facilities are nonetheless capable of: a) providing an Ancillary Service at a reduced level; b) meeting some but not all of the performance requirements for that Ancillary Service; or c) providing the Ancillary Service otherwise than in accordance with the applicable performance standards; Version: 01 Page 12 Effective Date: October 11, 2013

165 Ancillary Services Operational Requirements Appendix E the SO may issue a schedule, Dispatch Instructions or control instructions referred to in section 2.3 or 2.4 in respect of that Ancillary Service that reflects the reduced capability of the AS Facilities. Version: 01 Page 13 Effective Date: October 11, 2013

166 Ancillary Services Operational Requirements Appendix E ATTACHMENT 1 AS FACILITIES SPECIFIC INFORMATION Part A: Scope A.1 Each Ancillary Services Provider will submit to the SO the applicable Ancillary Services data as required by Table 1 as described in Part B. Part B: Quantity B.1 Other than in exceptional circumstances, the quantity of an Ancillary Service identified in Table 1 for a given AS Facility shall not exceed the maximum of the quantities of the Ancillary Service that the AS Facility is capable of providing at a various operating ranges. B.2 The quantity of Automatic Generation Control Service and Load Following Service are expressed in Table 1 as the quantity above or below the dispatched output level for energy such that the AS Facility shall be required to respond to activation signals to adjust its output to any value within the range thus defined. B.3 The quantities of Capacity-Based Ancillary Services are expressed in Table 1 on a cumulative basis such that the total quantity expressed for each such Ancillary Service is the total that can be dispatched for the then concurrent combination of all such Ancillary Services. B.4 The quantities of Capacity-Based Ancillary Services are expressed in Table 1 on the basis of an assumption that the AS Facility is not being ramped for energy dispatch purposes. Version: 01 Page 01 Effective Date: October 11, 2013

167 Ancillary Services Operational Requirements Appendix E Part C: Operating Range C.1 The operating range for an Ancillary Service is expressed in Table 1 in a manner that reflects that the actual quantities of the Ancillary Service that can be provided at any time will depend on the level of output to which the AS Facility is dispatched, the ramp limits at that level of output and any concurrent ramping of the energy output. C.2 Each Table 1 specifies, in respect of operating range information, the maximum combined ramping capability of the AS Facility in the provision of each Ancillary Service at each level of output, averaged over the relevant period and using a maximum of 10 ranges for the AS Facility. The term N/A when used in Table 1 in respect of operating range information shall mean that the applicable Ancillary Service cannot be provided by the AS Facility over a particular range of output. Part D: Amendments to Table 1 Data D.1 The Parties acknowledge that the data of Table 1 may need to be amended from time to time to reflect changes in the performance capabilities of the AS Facilities over time: a) the quantity of an Ancillary Service; and b) the operating ranges and ramping capabilities for the AS Facilities. D.2 Where the AS Provider wishes to amend data in Table 1 referred to in section D.1, the AS Provider shall provide to the SO an amended version of the Table 1 data for approval. D.3 The SO shall approve an amendment proposed by the AS Provider under section D.2 unless the SO considers that: a) the proposed amendment is frivolous; or b) the proposed amendment was submitted in bad faith, including for the purpose of allowing the AS Provider to avoid its commitments in circumstances where Version: 01 Page 02 Effective Date: October 11, 2013

168 Ancillary Services Operational Requirements Appendix E c) there has been no decrease in the performance capabilities of the AS Facilities or where the proposed amendment is out of proportion with the decrease in the performance capabilities of the AS Facilities. D.4 The SO shall consider a proposed amendment submitted to it under section D.2 as soon as reasonably practicable. The SO shall: a) accept the amendment as proposed by the AS Provider, in which case it will provide to the AS Provider an amended version of Table 1 in question. The amendment will come into effect on the day on which the amended version of Table 1 is sent to the AS Provider or such later date as the Parties may agree; or b) reject the proposed amendment, in which case it will so notify the AS Provider, together with reasons for its decision. Version: 01 Page 02 Effective Date: October 11, 2013

169 Ancillary Services Operational Requirements Appendix E Version: 01 Page 03 Effective Date: October 11, 2013

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