ANCILLARY SERVICES PROCUREMENT PLANerc.gov.ph/Files/Render/media/ERCCaseNo.2017-005RM-AnnexA.pdf · Units will provide Ancillary Services to implement the final Dispatch Schedule

ANCILLARY SERVICES PROCUREMENT PLAN

Rules, Terms and Conditions for the Maintenance of Reliability, Adequacy and Security of the Grid

Energy Regulatory Commission

ERC Case No. _______

Draft December 2016

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TABLE OF CONTENTS

1 Introduction ........................................................................................................ 2

1.1 Objectives ........................................................................................................... 2

1.2 Glossary .............................................................................................................. 2

1.3 Scope and Applicability .................................................................................... 5

1.4 Ancillary Services Categories .......................................................................... 5

1.4.1 Frequency Control Ancillary Service (FCAS) ............................................... 5 1.4.2 Reactive Power Support Ancillary Service (RPSAS) ................................... 6 1.4.3 Black Start Ancillary Service (BSAS) ........................................................... 6

2 Specification of Ancillary Services .................................................................. 6

3 Technical Requirements ................................................................................... 7

4 Required Levels of Ancillary Services .......................................................... 11

5 Procurement of Required Ancillary Services ............................................... 13

5.1 Methods of Procurement of Ancillary Services ............................................ 13

5.2 Methods of Scheduling and Dispatch of Ancillary Ser vices ...................... 14

5.3 Qualification and Testing of Service Providers ............................................ 18

5.4 Monitoring of Ancillary Service Provision .................................................... 20

5.5 Payment to Service Providers ....................................................................... 21

6 Ancillary Service Compliance Monitoring ..................................................... 21

7 Transitory Provisions ...................................................................................... 21

8 References ........................................................................................................ 22

Attachment 1- Certification of Ancillary Service Pr oviders ....................................... 24

Attachment 2 - Ancillary Service Testing, Certifica tion and Accreditation ............. 29

Attachment 3 – Ancillary Services Standard Technica l Requirements ................... 37

Attachment 4 – Generator Reactive Capability Limita tion ........................................ 39

Attachment 5 – Sample Computations ........................................................................ 40

Attachment 6 – Tertiary Reserve Interruptible Load Certification Test ................... 43

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1 Introduction 1.1 Objectives

The Ancillary Services Procurement Plan (ASPP) has been developed to inform the electric power industry participants how NGCP, through its System Operator, will undertake its responsibilities to provide Ancillary Services to the Philippine Grid, in coordination with the Market Operator, as required by the Electric Power Industry Reform Act of 2001 (EPIRA), the Implementing Rules and Regulations of Republic act No. 9136 (the IRR), the Philippine Grid Code, OATS Rules and the WESM Rules.

1.2 Glossary

Active Power - The time average of the instantaneous power over one period of the electrical wave measured in Watts (W) or multiple thereof. For AC circuits or Systems, it is the product of the root-mean-square (RMS) or effective value of the voltage and the RMS value of the in-phase component of the current. In a three phase System, it is the sum of the Active Power of the individual phases.

Automatic Generation Control (AGC) - The regulation of the power output of Generating Units in response to a change in system Frequency, so as to maintain the Power System Frequency within the predetermined limits.

Available Capacity - the dependable capacity, modified for equipment limitation at any time.

Maximum Available Capacity - Generating capacity equal to the registered maximum capacity (Pmax) of the (aggregate) unit less forced unit outages, scheduled unit outages, de-rated capacity due to technical constraints which include plant equipment-related failure and ambient temperature, hydro constraints which pertains to limitation on the water elevation/turbine discharge and MW output of the plant and geothermal constraints which pertain to capacity limitation due to steam quality (including, but not limited to, chemical composition, condensable and non-condensable gases), steam pressure and temperature variation, well blockage and limitation on steam and brine condensable gases), steam pressure and temperature variation, well blockage and limitation on steam and brine collection and disposal system

Energy Storage System – is a set of technologies where energy is stored during times when production exceeds consumption and the stored energy are used at times when consumption exceeds production.

Concessionaire - The concessionaire is currently the National Grid Corporation of the Philippines (NGCP), or as otherwise approved under Philippines law from time to time.

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Dependable Capacity - the maximum capacity, modified for ambient limitation for a specified period of time, such as a month or a season.

Dispatch Instructions – Refers to the instruction issued by the System Operator to the Generators with Scheduled Generating Units and to the Generators whose Generating Units will provide Ancillary Services to implement the final Dispatch Schedule in real time.

Dispatch Schedule (Market base) - The target loading levels in MW for each scheduleGenerating Unit or scheduled Loads and for each Reserve facility for the end of that trading interval determined by the Market Operator through the use of a market dispatch optimization model.

Dispatch Schedule (Non-Market base) . The target loading levels in MW for each scheduled Generating Unit or scheduled Loads and for each Reserve facility as determined by the System Operator.

Energy Management System (EMS) - An electronic monitoring and control system available to the System Operator to monitor and control the Grid.

Excess capacity - For a generator, excess capacity is the available output capacity in MW while it is supplying the scheduled energy, Primary, Secondary and Tertiary reserve dispatched by the System Operator or under contract (i.e.: available capacity less scheduled energy, Primary, Secondary and Tertiary reserve). Excess capacity = available capacity - (scheduled energy + scheduled AS reserves). Frequency – as defined in the Philippine Grid Code with a nominal value of 60Hz

Frequency Response Obligation - The minimum amount of Frequency Response that must be maintained by the System Operator in the Grid. It is a target contingency protection criterion which includes the reliability margin to prevent frequency nadir from encroaching the system’s highest Under Frequency Load Shedding (UFLS).

Grid - The high voltage backbone system of interconnected transmission lines, substations and related facilities, located in each of Luzon, Visayas and Mindanao, or as may be determined by the ERC in accordance with Section 45 of the Act.

Governor Control Mode (GCM) - A generating unit operating under the control of a governor which has been calibrated to control the output of the generating unit to set levels of frequency, voltage or other parameter, without the need for external control signals. (MVAR) - Mega Volt-Ampere Reactive

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National Grid Corporation of the Philippines (NGCP) - The entity which in 2009 has been awarded the concession to operate, maintain and expand the Philippine electricity Grid, in accordance with NGCP Franchise (RA9511), or asotherwise approved under Philippines law from time to time.

Open Access Transmission Service Rules (OATS Rules) – The set of rules that govern the implementation of the Open Access Transmission Services as approved by the ERC.

Philippine Grid Code (PGC or Grid Code) – The set of rules, requirements, procedures, and standards to ensure the safe, reliable, secured and efficient operation, maintenance and development of the high-voltage backbone Transmission System and its related facilities.

Qualified Interruptible Loads - A load that is tested, certified and monitored by the System Operator to provide Tertiary Reserve Ancillary Service.

Qualified Generating Unit – A Generating Unit tested, certified and monitored by the System Operator to provide specific types of Ancillary Service.

Qualified Generators - A generator which has one or more, Qualified Generating Unit(s) which have been tested and certified as qualifying under the provisions of this ASPP document (refer section 5.3), where only the Qualified Generating Units are eligible to be scheduled as and receive payments for providing AS. Reaction Time - The elapsed time from the occurrence of a disturbance until the time the ancillary service provider begins to respond.

Reactive Power Capability Curve - A diagram which shows the Reactive Power capability limit versus the Real Power within which a Generating Unit is expected to operate under normal conditions. Refer to Attachment 4 for an example.

Regular Energy Supply - Is defined as the output of energy by a generator at a given MW level and over a given time interval under dispatch orders of the System Operator.

Reserve Market – as defined in WESM Rules.

Saturation Time – The elapsed time from the occurrence of a disturbance until the time the ancillary service provider reaches the required reserve capacity.

Service Providers – Pertains to grid-connected Qualified Generators and Qualified Interruptible Loads.

Sustainability - The elapsed time from the saturation point until the time for which the ancillary service provider must maintain the appropriate reserve capacity.

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TransCo - The National Transmission Corporation of the Philippines, which is currently the owner of the electricity transmission assets of the Philippine Grid.

Under Frequency Relays (UFR) - An electrical relay that operates when the Power System Frequency decreases to a preset value.

Under-Frequency Load Shedding (UFLS) - The process of automatically and deliberately removing pre-selected Loads from a power System in response to under-frequency condition in order to maintain the integrity of the Power System.

Wholesale Electricity Spot Market (WESM) – The electricity market established by the DOE pursuant to Section 30 of the Act.

Where terms are not defined in this ASPP reference should be made to the EPIRA, IRR, Grid Code or WESM Rules.

1.3 Scope and Applicability

This document covers the definition of the types of Ancillary Services (AS) necessary for the reliable operations of the Grid, the manner of procurement by the System Operator, the level of Ancillary Services requirement, the process of certifying Qualified Generating Units and Qualified Interruptible Loads which the System Operator can contract and/or schedule for provision of Ancillary Services, and the process for control, monitoring Ancillary Services provider’s performance and the obligation for payments.

The cost recovery mechanism for the provision of scheduled Ancillary Services is defined in separate documents, which are subject to due process and approval by the ERC. Implementation of this procurement plan shall be in accordance with the guidelines to be develop by NGCP.

1.4 Ancillary Services Categories

All Ancillary Services can be grouped under one of the following three (3) major categories:

1.4.1 Frequency Control Ancillary Service (FCAS)

FCAS are used (by the System Operator) to maintain the frequency on the electrical system, at any point in time, close to sixty (60) cycles per second. There are three (3) types of reserve under Frequency Control as specified by the PGC.

• • Primary Reserve Ancillary Service (PRAS) • Secondary Reserve Ancillary Service (SRAS) • Tertiary Reserve Ancillary Service (TRAS)

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These types of FCAS will be defined in Section 2 of this plan.

1.4.2 Reactive Power Support Ancillary Service (RPSAS)

RPSAS are reactive power provided by generating units capable of operating at less than 0.85 lagging power factor or less than 0.90 leading power factor to maintain the system voltage at the standard level set in the PGC.

1.4.3 Black Start Ancillary Service (BSAS)

BSAS are used to recover the Power System from total or partial system blackout by starting and synchronizing with the Power System without an external power supply.

2 Specification of Ancillary Services

The following AS will be provided by Qualified Generators, Energy Storage System and Qualified Interruptible Loads in the Philippine Grid. These AS are essential in maintaining power quality, reliability, and security of the Philippine Grid.

2.1 PRAS – are FCAS capacities from qualified Generating Units and Energy Storage System that are allocated to stabilize the system Frequency and to cover the loss or failure of a Synchronized Generating Unit or a transmission line or the power import from a single circuit interconnection.

2.2 SRAS - are FCAS capacities from qualified Generating Units and Energy Storage

System that are allocated to restore the system frequency from the quasi-steady state value as established by the Primary Reserve back to the nominal frequency of 60 Hz. This type of service should also be used to provide supply demand balance during small frequency deviations.

2.3 TRAS - are FCAS capacities from qualified Generating Units, Energy Storage System and Interruptible Loads that are readily available for dispatch in order to replenish the Secondary Reserve and to cover variation of VRE generations. This type of service should also be used in maintaining the Frequency at a pre-established value and/or returning the Frequency to 60Hz in case the Primary and Secondary Reserve are not adequate or already exhausted.

2.4 RPSAS - is the capability of a generating or a synchronous condenser unit to supply reactive power to, or absorb reactive power from, the Transmission Network in order to maintain the bus voltage within five percent (5%) of its nominal voltage. The purpose is to supplement Reactive Power resources of the static and dynamic type, depending on the location and network loading conditions, and to contribute to network voltage control when dispatched.

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2.5 BSAS - The need for this AS arises when an event or significant incident will result in a Partial or Total System Blackout. This is the ability of a generating unit, without assistance from the Grid or other external power supply, to recover from a shutdown condition to an operating condition in order to energize the Grid and assists other generating units to start.

3 Technical Requirements

This section of the plan sets out the arrangements which the System Operator will follow for contracting or procurement of each category of Ancillary Services from Service Providers. On the other hand, the Service Provider shall use reasonable efforts, in accordance with good industry practice, to ensure that the plant and equipment meet the technical specification as per Philippine Grid Code requirement.

NGCP, as the System Operator, has certified numerous Service Providers. These Service Providers meet the performance criteria as evaluated based on the result of the capability tests. Included in this plan are the tabulated summaries of Performance Measures & Criteria with its monitoring scheme and the Accredited Service Providers for each category of ancillary services, once testing and certification has been performed by NGCP.

3.1 Primary Reserve Ancillary Service

Operating characteristics and technical capabilities of Generating Units and Energy Storage System providing Primary Reserve as AS:

3.1.1 The Generating Units or Energy Storage System providing Primary Reserve as an Ancillary Service shall be capable of operating in Governor Control mode with sufficient headroom.

3.1.2 The Generating Units or Energy Storage System providing Primary Reserve as an Ancillary Service shall be certified and contracted by the System Operator.

3.1.3 The Generating Units or Energy Storage System providing Primary Reserve as Ancillary Service shall not override its governor control. The Primary Reserve provider should be able to respond within 5 seconds and deliver its reserve capacity based on its Ramp-up Rate within 10 minutes which should be sustainable for at least 30 minutes or as required by the system.

3.1.4 Primary Reserve Service provider shall cover sudden outage or failure of synchronized generating unit or transmission line links or the power import from a single circuit interconnection, whichever is larger.

As an illustration, the Figure 3.1 below shows the relationship between Primary Reserve and Regular Energy Supply:

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Figure 3.1: Primary Reserve

3.2 Secondary Reserve Ancillary Service

Operating characteristics and technical capabilities of Generating Units and Energy Storage System providing Secondary Reserve:

3.2.1 Generators and Energy Storage System providing this service shall be controlled by SO thru AGC with Auto R, Auto A, or Auto E settings in order to regulate the system frequency. The speed governing system shall be capable of accepting raise and lower signals or set point signals from the Control Center of the System Operator. The Secondary Reserve provider should be able to deliver 90% of the desired generation within 32 seconds and should be sustainable for at least 30 minutes.

3.2.2 Generating Unit contracted to provide Secondary Reserve shall not override the AGC mode or AGC setting as set and controlled by SO.

3.2.3 The System Operator thru AGC shall use the Secondary Reserve to restore the system Frequency from the quasi-steady state value as established by the Primary Reserve back to the nominal Frequency of 60 Hz.

3.2.4 Where the AGC function of the SO is not fully operational, dispatcher may instruct the generator to transfer to Manual Control Mode.

3.2.5 The Secondary Reserve, operated thru AGC or manual control, shall be provided by Generating Units of Energy Storage System, both contracted and certified by the System Operator.

The capacity of the Generating Unit or Energy Storage System offered for this

service should not be used in the regular energy supply. Figure 3.2 below illustrates the Secondary Reserve Ancillary Service:

Primary Reserve Ancillary Service

Regular Energy Supply

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Figure 3.2: Secondary Reserve

3.3 Tertiary Reserve Ancillary Service

Operating characteristics and technical capabilities of Generating Units, Energy Storage System and Interruptible Loads providing Tertiary Reserve:

3.3.1 Generating Unit and Energy Storage System providing this service can either be synchronized, which can respond within 15 minutes, or off-line provided that it can fully provide the required reserve within 30 minutes from the receipt of dispatch instruction. The Tertiary Reserve provider should be able sustain its contributed capacity for at least 60 minutes.

3.3.2 The total Tertiary Reserve may comprise of 50% synchronized with the Grid and 50% off-line.

3.3.3 The System Operator shall make use of the Tertiary Reserve in cases of: (a) Unplanned tripping of a Generating Unit or a transmission line

which creates a Generation-Load unbalance; (b) Unplanned loss of the power import from a single circuit

interconnection; (c) Unplanned Disconnection of a large Load and/or Load blocks; (d) Unexpected reduction of VRE Generation or significant errors in its

forecast; or (e) System Frequency increases above 60.1 Hz or reduces below 59.9

Hz and it is not possible to return it to nominal values with appropriate use of the Primary and Secondary Reserve.

3.3.4 The System Operator shall use the Tertiary Reserve Service to replenish the Secondary Reserve.

3.3.5 The Tertiary Reserve shall be provided by Generating Units or Energy Storage System and Qualified Interruptible Loads contracted by the Transmission Network Provider and are certified by the System Operator.

3.3.6 Generators or Energy Storage System providing this service should be capable of operating thru AGC or Manual mode and shall be monitored and controlled by the System operator.

3.3.7 The capacity of the Generating Unit or Energy Storage System offered

Secondary Reserve

Pmin .

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for this AS should not be part of the regular energy supply. As an illustration, the Figure 3.3 below shows the relationship between Tertiary Reserve and Regular Energy Supply of a Generating unit already supplying energy.

Figure 3.3: Tertiary Reserve

3.3.8 Operating characteristics and technical capabilities of Interruptible Loads providing Tertiary Reserve:

3.3.8.1 Interruptible Loads providing Tertiary Reserve shall be able

to drop its committed loads 15 minutes after the receipt of Dispatch order from the System Operator.

3.3.8.2 Interruptible load shall be directly connected to the Grid in order to qualify as Tertiary Reserve.

3.3.8.3 Interruptible Loads providing Tertiary Reserve should have the capability to provide real time data (MW readings and Status of Load) to the NGCP SCADA/EMS.

3.3.8.4 Interruptible Load providing Tertiary Reserve should be able to provide a committed uniform load throughout the Dispatch Period. Interruptible Loads should also be able to stay off-line until ordered by the System Operator to re-connect to the Grid.

3.4 Reactive Power Support Ancillary Service

Operating characteristics and technical capabilities of Generating Units providing Reactive Power Support Ancillary Service:

3.4.1 The Generating units and synchronous condensers shall be capable of supplying its Active Power output, as specified in the Generator's Declared Data, at less than 0.85 Power Factor Lagging and less than 0.90 Power Factor Leading at the Generating Unit's terminals, in accordance with its Reactive Capability Curve (Refer to Attachment 4

Tertiary Reserve

Regular Energy Supply

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and Attachment 2 - Testing, Certification and Accreditation Procedure). 3.4.2 Outside of the above range, but within its Reactive Power Capability

Curve, the generating unit may offer to supply/absorb additional reactive power to/from the system if the System Operator so requires as an ancillary service.

3.5 Black Start Ancillary Service

Operating characteristics and technical capabilities of Generating Units providing Black Start Service:

3.5.1 Black Start plants must be put on-line and ready to extend power within thirty (30) minutes upon receipt of dispatch instruction and can sustain the operation for at least 12 hours.

3.5.2 Black Start and Fast Start capacity shall be: 3.5.2.1 Sufficient at strategic locations to facilitate the restoration of the

Grid to the normal state following a total System blackout. 3.5.2.2 Available at all times to facilitate the goal of a complete system

restoration in twelve (12) hours. 3.5.3 Redundancy of Black Start generation shall be taken into consideration

due to possibility of unit failure to start or transmission facility failures preventing units from serving their intended loads.

3.5.4 No more than one (1) unit of a Black Start plant with multiple black start units may be on planned maintenance at any one time.

3.5.5 When a Generating Unit becomes isolated from the Grid, the speed-governing system shall provide Frequency Control to the resulting island Grid (asynchronous control).

3.5.6 There shall be at least 50 MW of black start capability available per Restoration Highway in Luzon, 20 MW for Visayas and 25MW for Mindanao. However, the maximum Black Start capability shall be determined by the System Operator, subject to confirmation by the Grid Management Committee on an annual basis, taking into account the technical requirement and financial considerations.

4 Required Levels of Ancillary Services

4.1 Primary Reserve Ancillary Service

The minimum required level for this Ancillary Service is equivalent to the

Contingency Criterion as shown in Table 1 below as prescribed by the PGC 2016

Edition:

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Table 1: Frequency Response Obligation

Luzon Visayas Mindanao Uni ts Starting Frequency 60 60 60 Hz Target Minimum Frequency 59.2 59.2 59.2 Hz Contingency Protection Criterion 600 150 150 MW Frequency Response Obligation

(FRO),

75

20

20

MW/0.1 Hz

4.2 Secondary Reserve Ancillary Service

The minimum Secondary Reserve service level shall be computed on an hourly

basis and shall be the equivalent to minimum of 4% of the hourly forecast demand.

The level of Secondary Reserve on the hourly basis can be computed as follows:

SR h = F h D x 4.0%

Where:

SR h = Secondary Reserve for the hour "h" F h D = Forecast Demand for the hour "h"

Note: The 4.0% factor should be the minimum amount and this will be adjusted depending on the requirement to cater VRE output variability in the Grid.

4.3 Tertiary Reserve Ancillary Service

To meet the Grid requirement, there must be enough Tertiary Reserve in each Grid at any given time, as established by the System Operator. The minimum required level for this service shall be equal to the Secondary Reserve required level in a particular Grid in order to arm/bring back the Secondary Reserve in its required minimum level 15 minutes after receipt of dispatch instructions. Not more than 50% of Tertiary Reserve shall be allocated to Interruptible Loads during periods where Sufficient Reserve capacities are available from generators.

The level of Tertiary Reserve on the hourly basis for a particular Grid can be computed as follows:

TRAS h = SRAS h

4.4 Reactive Power Support Ancillary Service

The required level of Reactive Power Support Ancillary Service is dependent on the system condition. Reactive Power Support Ancillary Service from generators

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is at maximum during peak and off-peak periods. During peak periods, generators are made to operate at lagging power factor to produce reactive power. While on off-peak periods, some generators may be required to operate in leading power factor to absorb reactive power. As such, the reactive power requirement of the system can only be determined once the dispatch schedule of the generators is available. In determining the required Voltage Control Ancillary Service for the system, the System Operator will use a power system simulator (load flow software).

4.5 Black Start Ancillary Service

4.5.1 Black Start Ancillary Service shall be contracted to qualified generators considering there should be at least two (2) units contracted per power restoration highway and one (1) should always be available at any given time.

4.5.2 The system Operator shall determine regularly the best restoration highways or sub-grids where there are available contracted BSAS provider.

5 Procurement of Required Ancillary Services

5.1 Methods of Procurement of Ancillary Services

5.1.1 The following Ancillary Services (AS) will be procured by the National Grid Corporation of the Philippines (NGCP) from various Service Providers in the Philippine Grid:

• Primary Reserve Ancillary Service • Secondary Reserve Ancillary Service • Tertiary Reserve Ancillary Service • Reactive Power Support Ancillary Service • Black Start Ancillary Service

5.1.2 NGCP as the System Operator and mandated by the RA 9136 to secure

the Grid shall procure the following Ancillary Service in the least cost manner:

5.1.2.1. Primary Reserve Ancillary Service – Through long term ASPA

which should not be included in the WESM Energy and Reserve co-optimization.

5.1.2.2. Secondary Reserve Ancillary Service – Through long term

ASPA which should not be included in the WESM Energy and Reserve co-optimization.

5.1.2.3. Tertiary Reserve Ancillary Service – Through ASPA or WESM

Reserve Market which could be co-optimized with the energy market provided that there is sufficient mitigating measure to prevent abuse of market power such as but not limited to

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secondary price cap for reserves approved by the ERC. 5.1.2.4. Reactive Power Support and Black Start Ancillary Services –

Through long term ASPA only.

5.2 Methods of Scheduling and Dispatch of Ancillary Ser vices

5.2.1 Ancillary Service Response Monitoring

5.2.1.1. The system operator will regularly monitor the performance of the AS providers. The data from NGCP's SCADA/EMS will be used in monitoring the AS compliance.

5.2.1.2. In monitoring for AS providers operating in governor control mode, data from SCADA/EMS, particularly; System Frequency and Unit MW output will be analyzed regularly and compared with the scheduled values for the particular services. Similarly, the actual MVAR output and Substation voltages data from SCADA/EMS will be analyzed and compared with the scheduled values.

5.2.1.3. The actual synchronization time of black start providers are also

monitored using the Alarm/Event subsystem of the SCADA/EMS.

5.2.2 Reserve Requirement Determination

SO shall prescribe the level of reserve requirement for each Grid based on the results of assessment and simulation study and shall update the MO the level of reserve required by each Grid that will be used on their daily computation.

5.2.2.1. MO shall Generate reserve requirement for Primary Reserve, Secondary Reserve and Tertiary Reserve based on 1200H DAP run in accordance to reserve level provided by SO based on the results of assessment and simulation study.

5.2.2.2. MO shall submit the reserve requirements to SO on or before 1300H Day-Ahead for review and validation.

5.2.2.3. SO shall submit to MO changes of reserve requirement if any,

on or before 2000H Day-Ahead.

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5.2.3 Scheduling Protocol

5.2.3.1 NGCP Contracted

5.2.3.1.1 NGCP Service Providers shall submit a nomination to the SO day-ahead for approval.

5.2.3.1.2 SO shall send back the approved schedule to the NGCP- Service Providers day-ahead.

5.2.3.1.3 NGCP- Service Providers shall nominate to the MO the NGCP approved schedule for the particular trading interval.

5.2.3.1.4 MO shall provide the SO with the Real-Time Dispatch (RTD) containing energy and ancillary services requirement for the trading interval.

5.2.3.2 Responsibilities of the Parties (SO/MO and AS providers):

5.2.3.2.1 The Service Providers shall submit daily to the System Operator on or before 1400H of the day preceding the dispatch day the following data:

o Status of Black Start equipment (for Black Start providers)

o Hourly day-ahead capacity nominations for service providers delivering PRAS, SRAS, TRAS, RPSAS and BSAS services

5.2.3.2.2 SO shall prepare and issue to the Service Providers on or before 1700H the hourly day-ahead schedule for PRAS, SRAS, TRAS, RPSAS and BSAS. This Ancillary Service Day-ahead Schedule will be based on the following:

o Hourly reserve requirement; o Ancillary capacity nomination; o Nominated capacity and price of each AS Provider; o Available Black Start units per restoration highway;

and o Voltage Control Ancillary Service Requirement of the

System.

5.2.4 Dispatch Protocol

5.2.4.1 SO and/or the RCC dispatches all plants’ Real-Time-Dispatch schedule provided by the MO according to reserve dispatch

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implementation procedure. SO may undertake re-dispatch procedures in the event of the following conditions:

o Outage of Transmission Lines or Substation Facilities; o Violation of System Security Limits; o Total System Failure; o Unexpected Reduction of Generation Availability; o Force Majeure Events; or o Emergency Security Measures.

5.2.4.2 Service Providers shall implement the dispatch instructions and

ensure to provide their required Ancillary Services.

5.2.4.3 SO shall monitor the compliance of Ancillary Services providers based on the approved Ancillary Services provider schedule using the SCADA system and available meter data.

5.2.5 Tradable Ancillary Services under the WE SM Regime

In case NGCP decides to procure the Tertiary Reserve Ancillary Service from the Reserve Market, the scheduling shall be ba sed on the WESM Dispatch protocol.

5.2.5.1 Non-NGCP contracted Service Providers shall nominate to the

MO the reserve capacity. 5.2.5.2 MO shall include all the nominations received and shall be

incorporated in the market optimization model. 5.2.5.3 MO shall provide the SO the Real-Time Dispatch containing

the scheduled Energy and Ancillary Services for both contracted and Reserve Market nominations.

Figure 5.2.5 below shows the process flow for the trading of Ancillary Services within the WESM as described in this section.

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Figure 5.2.5. Trading Process Flow for Tertiary Res erve Ancillary Service

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5.3 Qualification and Testing of Service Providers

NGCP, as the System Operator, may use reasonable endeavors to procure Ancillary Services from Qualified Generation Units and Qualified Interruptible Load providers in order to maintain a sufficient level of Ancillary Services to the Grid. To qualify as providers of Ancillary Services all prospective providers should have undergone the certification process as defined in the PGC. If a provider has already been certified as a qualified Ancillary Services provider, a verification testing will be conducted no more than one (1) every two (2) years except when there are reasonable grounds to consider such that the characteristics of the Generating Unit parameters differs from those registered and/or it is not complying with any prescription of the PGC.

Aside from the certification, NGCP requires that all certified providers should have fully functional direct interface with NGCP's SCADA/EMS. This means that relevant real time data such as; MW, MVAR, KV, Circuit breaker or unit status and mode of control of the qualified providers are available at the System Operators control centers. All AS capability tests shall be conducted by the prospective AS providers to show proof to NGCP their ability to provide AS. Upon evaluation of the test results, NGCP shall issue a certificate indicating the type of AS, applicable capacity for AS and its validity. The following AS capability tests will be conducted for all interested prospective AS providers:

5.3.1 Primary Reserve Capability Test

5.3.1.1 The prospective AS providers shall prove to NGCP their capability to provide this service. Generators or ESS intending to provide this kind of service should prove that their speed governing can respond to + 0.15 Hz or less for generators and +0.06 Hz for ESS. The AS provider should be able to produce the nominated reserve based on the Ramp-up Rate within 10 minutes. Refer to the Ancillary Services Testing, Certification and Accreditation Procedures (Attachment 2) and Ancillary Services Standard Technical Requirements (Attachment 3).

5.3.2 Secondary Reserve Capability Test

5.3.2.1 The prospective Generating Unit AS providers shall prove to NGCP their capability to provide this service. This includes their ability to respond to AGC command signals (from the SCADA/EMS of the System Operator either raise/lower or analog signals). Capable to produce 90% of the nominated reserve within 32 seconds and passed 90% of the total samples. Refer to the Ancillary Services Testing, Certification and Accreditation Procedures (Attachment 2) and Ancillary Services Standard Technical Requirements (Attachment 3).

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5.3.3 Tertiary Reserve Capability Test

5.3.3.1 The prospective AS providers shall prove to NGCP their capability to provide this service. Generators or Energy Storage System can provide this kind of service whether synchronized in the Grid or off-line and should prove that their units can produce the nominated capacity within thirty (30) minutes and sustain their operation for at least two (2) hours. Generators and Energy Storage System may at their own option prove their ability to respond to AGC command signals (from the SCADA/EMS of the System Operator either raise/lower or analog signals). Refer to the Ancillary Services Testing, Certification and Accreditation Procedures (Attachment 2) and Ancillary Services Standard Technical Requirements (Attachment 3).

5.3.3.2 On the other hand, Interruptible Loads intending to supply this type of

service should prove that their nominated load demand can be dropped fifteen (15) minutes after receipt of instruction from the System Operator and should not re-connect that load until instructed by the System Operator to do so. Refer to the Ancillary Services Testing, Certification and Accreditation Procedures (Attachment 2) and Ancillary Services Standard Technical Requirements (Attachment 3).

5.3.4 Reactive Power Support Capability Test

5.3.4.1 The prospective AS providers shall prove to NGCP their capability to provide this service. Generators intending to provide this kind of service should prove that their units can operate outside the PGC required power factor range (85% PF lagging to 90% PF leading) to produce and absorb reactive power. Refer to the Ancillary Services Testing, Certification and Accreditation Procedures (Attachment 2) and Ancillary Services Standard Technical Requirements (Attachment 3).

5.3.5 Black Start Capability Test

5.3.5.1 The prospective AS providers shall prove to NGCP their capability to provide this service. Generators should be able to start on its own without any feedback power from the Grid within thirty (30) minutes and should be able carry load and successfully energized their assigned Blackout Restoration Highway. Refer to the Ancillary Services Testing, Certification and Accreditation Procedures (Attachment 2) and Ancillary Services Standard Technical Requirements (Attachment 3).

5.3.6 Failure of Capability Test & Re-Test Period

5.3.6.1 Certified plants that fail in the capability test should endeavor

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to correct the deficiency as required in the PGC, within a reasonable period of time less than sixty (60) days from the date of the failed test, otherwise these plants may not be allowed to offer their AS in that annual period.

5.3.6.2 The System Operator will report to ERC the Service Providers that failed to rectify the deficiencies of the capability test, within the reasonable period of sixty (60) days.

5.3.6.3 After the failure of the capability test, follow-up testing should be conducted by the NGCP on a date agreed with the AS provider. Such date should fall within sixty (60) days of the written request from NGCP to rectify the reasons for failure.

5.3.7 Testing of Service Providers

5.3.7.1 Scheduled tests shall be conducted to confirm the compliance of Generating Units' capability and availability to deliver the Ancillary Services that the Generator had agreed to provide. All tests shall be recorded and witnessed by the authorized representatives of NGCP and the Service Providers. The test procedures in Attachment 2 will be used in these tests.

5.4 Monitoring of Ancillary Service Provision

5.4.1 Capability Re-Test Trigger Report

5.4.1.1 The System Operator will provide a written exception report where the monitoring of an AS provider demonstrates a breach in its capability requirements on two consecutive monitoring instances. Such monitoring to occur at the discretion of the System Operator but should be a minimum of once per day, on two consecutive days, where an issue is identified.

5.4.1.2 Where a monitoring exception report is issued by the System Operator, the System Operator can trigger a re-test of the AS provider's capability to prove or disprove whether the AS provider can continue to be scheduled and paid for a particular AS. The scheduling and payment for AS to this AS provider is suspended from the date of the issuance of the exception report, until the AS provider capability is re-tested and certified in writing by the System Operator.

5.4.1.3 The AS provider can request in writing to the System Operator a delay of no more than sixty (60) days before the re-test in order to rectify or replace any control or other equipment which has caused the failure of the

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capability monitoring.

5.4.1.4 Re-testing shall occur, on a date agreed between the System Operator and the AS provider. The scheduling and payment for AS to this AS provider can only commence once a successful capability test has been achieved, and the AS has been successfully re-scheduled under the normal mechanism for scheduling specified elsewhere in the ASPP or related documents.

5.5 Payment to Service Providers

5.5.1 Payment to Service Providers shall be based on the ERC-approved Ancillary Service Procurement Agreement (ASPA).

5.5.2 Penalties for non-compliance will be included in the statement of accounts at the

end of the billing period.

5.5.3 The Service Providers receive, evaluate and validate the submitted statement of account prepared by NGCP-and/or the SO and return it for billing settlement.

5.5.4 NGCP and/or the SO shall submit monthly report on Ancillary Services schedule to ERC no later than the 15th day of the succeeding month.

6 Ancillary Service Compliance Monitoring 6.1 SO shall monitor the compliance of Ancillary Services providers based on the approved

Ancillary Services provider schedule using the SCADA system and available meter data. Penalties for non-compliance will be included in the statement of accounts at the end of the billing period.

6.2 The Service Providers receive, evaluate and validate the submitted statement of account prepared by NGCP-and/or the SO and return it for billing settlement.

7 Transitory Provisions

All approved and existing ASPA shall remain in full force and effect until their termination date, unless the accredited power plant of the AS Provider cannot comply with the technical requirements provided in the 2016 PGC. Accordingly, the AS categories of the ASPA will be converted as follows: i. Contingency Reserve – Primary Reserve; ii. Dispatchable Reserve – Tertiary Reserve; and iii. Regulating Reserve – Secondary Reserve.

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However, the AS Provider with an existing ASPA may opt to renegotiate its offer in a new ASPA that will be filed to the Honorable Commission for approval.”

8 References Unless otherwise amended and approved by the ERC, the following references are relevant to interpreting the terminology used in these ASPP.

1. Electric Power Industry Reform Act of 2001, (EPIRA), Republic Act No. 9136. 2. Philippine Grid Code 2016 Edition. 3. Philippine Distribution Code, December 2001. 4. Wholesale Electricity Spot Market (WESM) Rules, 2002. 5. Open Access Transmission Services (OATS) Rules, 2006. 6. Ancillary Services Cost Recovery Mechanism (ASCRM), September 2006. 7. Guide to Ancillary Services in the National Electricity Market, by Australian Energy Market

Operator 8. Reserve Market Arrangements under Section 3.3 of the WESM Rules, administered by

the Market Operator (MO) and the System Operator (SO).

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ATTACHMENT

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Attachment 1- Certification of Ancillary Service Providers

1.0 PURPOSE

1.1 This Attachment establishes guidelines to be followed on the certification of

Ancillary Service Providers who would like to provide Ancillary Services to ensure quality of power delivered through the Grid.

2.0 SCOPE

2.1 This Attachment covers only the certification process including contracting for Ancillary Service Providers.

3.0 DEFINITION OF TERMS/ACRONYMS

3.1 Definition of Terms

3.1.1 Ancillary Service Provider - a person or entity providing Ancillary Services regardless of whether it is duly registered or not with the Market Operator, provided, however, that upon accreditation by the System Operator and prior to trading in the WESM, it shall register with the Market Operator.

3.1.2 Ancillary Services - As defined in the Grid Code and WESM Rules.

3.1.3 Generator - any person or entity authorized by the ERC to operate a facility used in the generation of electricity.

3.1.4 System Operator - the section within the Transmission Provider’s

organization responsible for generation dispatch, or the implementation of the generation dispatch schedule of the Market Operator, the scheduling and dispatch of Ancillary Services, and operation to ensure the safety, power quality, stability, reliability, and the security of the Grid.

3.1.5 Transmission Provider - The Concessionaire with the exclusive national franchise for the operation, maintenance and expansion of the Grid, as provided for in RA 9511. For the avoidance of doubt, the Transmission Provider includes the System Operator.

3.2 Acronyms

3.2.1 ACC - Area Control Center 3.2.2 ASP - Ancillary Service Provider 3.2.3 AS - Ancillary Service 3.2.4 NCC - National Control Center 3.2.5 OPD - Operations Planning Division 3.2.6 SCADA - Supervisory Control and Data Acquisition 3.2.7 SO - System Operations or System Operator 3.2.8 TransCo - National Transmission Corporation 3.2.9 NGCP - National Grid Corporation of the Philippines, the

concessionaire for TransCo’s assets.

Page 25 of 44

4.0 REFERENCES

4.1 Philippine Grid Code 2016 Edition

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5.0 PROCEDURE

FLOWCHART RESPONSIBILITY DETAILS

Transmission Provider

1. The Transmission Provider, upon receipt of application for accreditation and required documents, will perform initial evaluation based on the technical requirements in Section 3 of this ASPP.


2. Notify and coordinate with the ASP regarding the test to be performed. Check the availability of test equipment and tools for testing.


3. Coordinate with NCC/ACC and OPD for the schedule of testing.

Generator 4. Conduct the test to be witnessed by the authorized representative of the Transmission Provider.

START

1 Receive Application for Accreditation as Ancillary Service Provider

2 Preparation for Plant Testing

3 Coordination with the concerned NGCP-SO Group

A

4 Proceed with the test

B

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Generator 5. Generator shall correct the deficiency of its generating unit/s within an agreed period to attain the relevant registered parameters for that unit/s.

Generator 6. The Generator shall immediately notify the Transmission Provider once the generating unit/s achieves the registered parameters.


7. Transmission Provider shall require the plant to conduct a retest in order to demonstrate that the appropriate parameter has already been restored to its registered value.


8. Issue Certification to ASP

A

Test successful?

5 Correction of plant deficiency

6 Notification to Transmission Provider regarding corrected parameters of generating units

B

7 Request to carry out a re-test

8 Issuance of certificate

C

NO

YES

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9. Negotiate with ASPs regarding the details of the contract/agreement.


Generator

10. Prepare Memorandum of Agreement/Contract for signature of both parties concerned.

C

9 Proceed with the negotiation

END

10 Contract preparation/signing

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Attachment 2 - Ancillary Service Testing, Certifica tion and Accreditation

1.0 PURPOSE To establish the guidelines to be used by NGCP for testing plant for certification to provide Ancillary Services; and for the Issue of Certification/Accreditation as an Ancillary Service Provider.

2.0 SCOPE This procedure covers the testing and certification of Ancillary Services Providers for Primary Reserve, Secondary Reserve, Tertiary Reserve, Reactive Power Support and Black Start Ancillary Services as required by the Philippine Grid Code.

3.0 DEFINITIONS OF TERMS/ACRONYMS

3.1 Definition of Terms 3.1.1 Ancillary Service Provider(s) – A person or entity providing Ancillary Services

regardless of whether it is duly registered or not with the Market Operator, provided, however, that upon certification by the Transmission Provider and prior to trading in the WESM, it shall register with the Market Operator.

3.1.2 Ancillary Services – Support services that are necessary to support the transmission capacity and flow of Active Power in order to maintain power quality and the reliability and security of the Grid. Ancillary Services covered by this Ancillary Services Procurement Plan include Primary Reserve, Secondary Reserve, Tertiary Reserve, Reactive Power Support and Black Start.

3.1.3 Automatic Generation Control (AGC) – The regulation of the power output of generating units within a prescribed area in response to a change in Power System Frequency, tie line loading, or the relation of these to each other, so as to maintain the Power System Frequency or the established interchange with other areas within the predetermined limits or both.

3.1.4 Black Start - the process of recovery from total system blackout using a generating unit with the capability to start and synchronize with the Power System without an external power supply.

3.1.5 Primary Reserve Ancillary Service – are capacities from qualified Generating Units and Energy Storage System that are allocated to stabilize the system Frequency and to cover the loss or failure of a Synchronized Generating Unit or a transmission line or the power import from a single circuit interconnection.

3.1.6 Control Center – a facility used for monitoring and controlling the operation of the Grid, Distribution System, or a User System.

3.1.7 Dispatch Instruction – refers to the instruction issued by the System Operator to the generators with scheduled generating units and the generators whose generating units provide ancillary services to implement the final dispatch schedule in real time.

3.1.8 Tertiary Reserve Ancillary Service - are capacities from qualified Generating Units, Energy Storage System and Interruptible Loads that are readily available for dispatch in order to replenish the Secondary Reserve and to cover variation of VRE generations. This type of service should also be used in maintaining the

Page 30 of 44

Frequency at a pre-established value and/or returning the Frequency to 60Hz in case the Primary and Secondary Reserve are not adequate or already exhausted.

3.1.9 Frequency – is the number of complete cycles of a sinusoidal current or voltage per unit time, usually measured in cycles per second or hertz.

3.1.10 Frequency Control – is a strategy used by the System Operator to maintain the frequency of the Grid within limits prescribed by the Grid Code by the timely use of Primary Reserve, Secondary Reserve, and Demand Control.

3.1.11 Generator – is an entity authorized by the Energy Regulatory Commission to operate a facility used in the generation of electricity.

3.1.12 Power Factor – the ratio of Active Power to Apparent Power. 3.1.13 Primary Response – is the automatic response of a Generating unit to

Frequency changes, released increasingly from zero to five seconds from the time of frequency change, and which is fully available for the next 25 seconds. The unit operates in a Governor Control mode at dead band setting within + 0.15 Hz.

3.1.14 Reactive Power – the component of electrical power representing the alternating exchange of stored energy (inductive or capacitive) between sources and loads or between systems, measured in VAR or multiples thereof. For AC circuits or systems, it is the product of the RMS value of the voltage and the RMS value of the quadrature component of the alternating current. In a three phase system, it is the sum of the reactive power of the individual phases.

3.1.15 Reactive Power Capability Curve – a diagram which shows the reactive power capability limit versus the real power within which a generating unit is expected to operate under normal condition.

3.1.16 Reactive Power Support - the injection or absorption of reactive power from Generators to maintain Transmission System voltages within ranges prescribed in the code.

3.1.17 Secondary Reserve Ancillary Service – are capacities from qualified Generating Units and Energy Storage System that are allocated to restore the system frequency from the quasi-steady state value as established by the Primary Reserve back to the nominal frequency of 60 Hz. This type of service should also be used to provide supply demand balance during small frequency deviations.

3.1.18 Secondary Response – is the automatic response to frequency change which is fully available 25 seconds from the time of frequency change to take over from the Primary Response, which is sustainable for at least 30 minutes.

3.1.19 Toolbox Meeting - a brief meeting done before the start of any activity to give everyone clarity about what needs to be done and why. It is also a way of dealing with any issues up front, and of improving teamwork through better (2-way) communication.

3.1.20 Voltage – the electromotive force or electric potential difference between two points which causes the flow of electric current in an electric circuit.

3.2 Acronyms

3.2.1 ACC – Area Control Center 3.2.2 ACTO – Assistant Chief Technical Officer 3.2.3 AGC – Automatic Generation Control 3.2.4 ASP – Ancillary Service Provider 3.2.5 ASPP – Ancillary Service Procurement Plan 3.2.6 BS – Black Start 3.2.7 DGS – Day-ahead Generation Schedule

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3.2.8 FR – Frequency Regulation 3.2.9 LSO – Luzon System Operations 3.2.10 MSO – Mindanao System Operations 3.2.11 MW – Megawatt 3.2.12 MVAR – Mega Volt-Ampere Reactive 3.2.13 MEX – Maximum Excitation Level 3.2.14 NOD – Network Operations Division 3.2.15 OPS – Operations Planning Section 3.2.16 PF – Power Factor 3.2.17 PQA – Power Quality Analyzer 3.2.18 PR – Primary Reserve 3.2.19 PRH – Power Restoration Highway 3.2.20 RCC – Regional Control Center 3.2.21 RPS – Reactive Power Support 3.2.22 RSO – Regional SO 3.2.23 SR – Secondary Reserve 3.2.24 SCADA – Supervisory Control and Data Acquisition 3.2.25 SO – System Operations 3.2.26 TR – Tertiary Reserve 3.2.27 VSO – Visayas System Operations

4.0 GENERAL REQUIREMENTS 4.1 The Annual Ancillary Service Test Schedule is already approved. 4.2 The RCC was informed of the scheduled test. 4.3 Test equipment to be used must be according to standard. 4.4 Personnel assigned to conduct the test should be qualified and knowledgeable. 4.5 Utmost safety of the plant is a priority. Abort the test if conditions will lead to plant

tripping. 4.6 The test equipment is installed to monitor the unit output MW, MVAR, KV and the

system frequency. 4.7 System at normal condition. 4.8 For reactive power test, voltage variation in the system should not exceed + 5% at

the connecting point. Compensation should be readily available from other generating units to limit voltage within the prescribed limits.

4.9 For reactive power test, the generator capability curve shall be the basis for MVAR loading.

4.10 For Primary Reserve test, the unit is on-line and operating in Governor Control mode.

5.0 REFERENCES 5.1 PM-NGCP-01 – Control of IMS Document

Philippine Grid Code 2016 Edition

Page 32 of 44

6.0 PROCEDURE

ACTIVITY RESPONSIBILITY DETAILS

PNPD/RSO 1.1

1.2

PNPD/RSO upon receipt of required documents and endorsement from RRA for accreditation will perform an initial evaluation for the particular Ancillary Service(s) applied for based on the standard technical requirements. Note: This is applicable only to new providers. Generators which have already been certified are scheduled for an Ancillary Service test for renewal of certification based on the approved work plan schedule of Ancillary Service Section of PNPD annually.

For BS Ancillary Service Test, the following shall be considered: 1.2.1 Annual BS test energization is up to

the Plant switchyard only for renewal of certification/accreditation.

1.2.2 A BS test shall be extended only to its

power restoration highway if either of the following conditions exist:

1. Newly commissioned power plants. 2. Newly refurbished power plants 3. For a certified BS provider, if there is

no black-out within the effectivity of Ancillary Services Procurement Agreement.

4. New restoration highway. 1.2.3 Representative from ACC/RCC will

conduct the BS test if the activity will be extended to its restoration highway.

1.3 Prepare Notice of Meeting to be signed by

Regional Head addressed to all concerned groups (copy furnish NOD, ACTO-SO).

START

A

1. Receive Application for Accreditation as Ancillary Service Provider

Page 33 of 44

D

Head, PNPD

2.1

Review and endorse test plan, applicable Instruction Manual/s and schedule.

Head, RSO 3.1 Head, RSO approve the scheduled AS test. The office of RSO Head shall provide copy to ACTO-SO and Head-NOD for information.

Head Engineer/ Representative-

ASS Plant- Operations

Grid Dispatcher /Plant Electrical

Maintenance Engineer

(Other NGCP group concerned

if applicable)

4.1

Conduct toolbox meeting with all concerned groups with the following agenda: 4.1.1 Schedule of certification test providing

for the required 7-days lead time and taking into consideration the following: 1. Inclusion of the schedule in the

DGS for non-market based operation.

2. For market-based operation, inclusion of the schedule in the non-security limits as needed.

3. Final schedule shall have the concurrence of all parties involved.

4.1.2 Test plan and applicable Instruction

Manual/s such as: 1. SR test manual 2. PR test manual 3. RPS test manual 4. BS test manual 5. TR test manual 6. IL (TR) test manual

4.1.3 Logistical requirements which include:

1. Service vehicle and accommodation.

2. PQA, test manuals, technical charts and previous results.

3.

A

3. Approve the AS Test Schedule

4. Conduct Toolbox Meeting with all Concerned Groups

2. Recommend Test Procedure and Schedule for Approval

B

Page 34 of 44

4.1.4 Minutes of meeting shall be properly

recorded and signed by all parties involved.

Head Engineer / Lead Engineer,

ASS/PNPD/RSO Plant Operations Grid Dispatcher /Plant Electrical

Maintenance Engineer

5.1

5.2

5.3

Conduct on-site briefing and discussion on the basic requirements prior to the AS test such as: 5.1.2 Electrical technicians to connect the

PQA. 5.1.3 Other technical diagrams, like Power

Capability Curve, etc.

ASS shall decide on the sequence of the test with confirmation from Plant Operations and Grid Dispatcher.

Conduct any or combination of the following AS tests based on the particular request for certification/ accreditation:

1. PR AS Test 2. SR AS Test 3. TR AS Test 4. RPS AS Test 5. BS AS Test

Duration of tests is based on the approved time and schedule which had been submitted to the OPS for clearance and implementation.

Head, ASS-PNPD

Shift In-Charge, Plant

Others (as may be applicable)

6.1

6.2

AS Test results shall be signed by the following:

1. Head Engineer, ASS 2. Shift-In-Charge, Plant 3. Plant Manager (if present) 4. PNPD Head (if present)

Furnish Plant Shift-In-Charge initial copies of the AS Test reports.

Engineer, ASS/PNPD/RSO

7.1

Generate, process, analyze and submit to Head Engineer, ASS/PNPD-RSO on the 12th working day the test results.

5. Conduct the AS test

6. Sign initial AS test result documents

7. Process, evaluate and analyze the AS test result

B

C

Page 35 of 44

YES

NO

E

Head Engineer, ASS/PNPD/RSO

8.1

Prepare and submit on the 15th working day after the test, the Plant Ancillary Service tests final report.

9.1

9.2

If the final AS test results conform to the standards, recommend for certification. If the final test report did not meet the required technical standards, inform Generator, copy furnish ACTO.

Head, Regional SO

10.1

10.2

Endorse Generator AS test report. Recommend/Endorse certificate to ACTO-SO for approval.

ACTO, SO 11.1 Approve certificate. Note: Validity of Certificate is two years. However, re-test may be conducted subject to RRA’s approval when there are reasonable grounds to consider such that the characteristics of the Generating Unit parameters differs from those registered and/or it is not complying with any prescription of the PGC.

Engineer, ASS 12.1

12.2

Send original copy of accreditation/certification to Generator and provide scanned copy to RRA and office of the CTO. Update database of ASP.

9. Test Passed?

10. Endorse Generator AS test report /Recommend certification

11. Sign/Approve Certificate

12. Provide copy of Accreditation Certificate to Generators and RRA

End

8. Prepare final Generator AS test report

C

Page 36 of 44

Head Engineer, ASS/PNPD/RSO

13.1 Discuss the test result with the Generator that the AS Technical requirements were not met.

14.1 If reasons are acceptable, reconsider Generator’s request for a re-test. Otherwise, tag the test as failed.

Generator 15.1 The Generator shall request to carry-out a re-test. (Repeat task 4 – 8).

E

13. Clarify with Generator the Final Report

14. Reasons

Accepted?

D

15. Request to carry-out a re-test

YES

NO

End

Page 37 of 44

Attachment 3 – Ancillary Services Standard Technica l Requirements

Reserve Type Performance Measures

Accreditation Testing Compliance Monitoring

Performance Criteria Monitoring Scheme Performance Criteria Monitoring

Scheme

Primary Reserve (GCM)

Capacity, MW 100%

1. PQ Analyzer 2. Plant’s DCS

100% 1. NGCP

EMS/SCADA & AS Web

• Continuous monitoring

• Actual Dispatch

2. Dispatcher’s E-log

Speed Droop setting 5% or less 5% or less Droop Response

(MW/Hz) ≥80% ≥80%

Deadband setting, (±) Hz

0.15 or less (Gen) 0.06 (ESS)

0.15 or less (Gen) 0.06 (ESS)

Reaction 5 seconds 5 seconds

Saturation Based on the Ramp-up

Rate within 10 min. Based on the Ramp-up

Rate within 10 min.

Sustainability N/A 30 minutes or as required by the system

Secondary Reserve (AGC or Manual if AGC is not operational)

Capacity, MW Based on actual

testing

1. NGCP EMS/ SCADA (For AGC)

Within ±1% scheduled

1. NGCP EMS/SCADA & AS Web


• Actual Dispatch


Deadband setting, (±) Hz 0.08 0.08 or greater

Reaction

90% of the desired generation should be

reach within 32 seconds.

Passed 90% of the total samples.

90% of the desired generation should be

reach within 32 seconds.

Saturation 32 seconds 32 seconds Sustainability N/A 30 minutes (minimum)

Tertiary Reserve (Manual for

providers coming from shutdown or AGC For on-line

providers)

Capacity, MW

Based on actual testing (AGC)

Based on Saturation – 30 min. (Manual)


Within ±1% scheduled (Luz)

Within ±3% scheduled (Vis/Min)



• Actual Dispatch


Reaction 15 minutes 15 minutes Saturation 30 minutes 30 minutes

Sustainability 120 minutes (Manual) N/A (AGC)

60 minutes (minimum)

Tertiary Reserve applicable to

Interruptible Load

Reaction 15 minutes after the

dispatch order


15 minutes after the dispatch order



• Actual Dispatch


Frequency Activation 59.4 Hz 59.4 Hz

Sustainable Load Reduction

uniform load throughout the dispatch period

uniform load throughout the dispatch period

Minimum Interruptible Load, MW

At least 1 MW per Provider

At least 1 MW per Provider

Black Start Service

Capacity Based on the capacity of the unit under test

1. Plant’s DCS

Not Required (as long as it had

successfully energized its Power Restoration

Highway)



• Actual Dispatch


3. Simulated emergency exercises

Reaction Within 30 minutes Within 30 minutes

Sustainability

Not Required (as long as it had

successfully energized its Power Restoration

Highway)

12 Hours

Page 38 of 44

Reserve Type Performance Measures

Accreditation Testing Compliance Monitoring

Performance Criteria Monitoring Scheme Performance Criteria Monitoring

Scheme

Reactive Power Support Service

Capacity Actual dispatch capability


Adjustment of power factor until voltage

correction is achieved



• Actual Dispatch


Power Factor within Reactive Power Capability Curve

Less than 0.85 pf lagging and less than

0.90 pf leading

Less than 0.85 pf lagging and less than

0.90 pf leading

Page 39 of 44

Attachment 4 – Generator Reactive Capability Limita tion

Page 40 of 44

Attachment 5 – Sample Computations

Section 4.5 Payment to Ancillary Services Providers

Note: These are sample computations for the current ASPAs approved by the Energy Regulatory Commission. Payment computation may chan ge over time when the ERC approves a different payment mechanism for new ASPA s. A. Primary Reserve (PR) �� = �� ℎ� �� + �� − �� Where:

�� ℎ� �� = � �� ℎ� �� × �� !"#

�� = $� �# % × �� ! + &��'��""( − )�*+��,��-�

If computed Incidental Energy < 0, set value of Incidental Energy payment at 0 Scheduled Capacity (SC), kW = 50,000 Undispatched Capacity, kW = 35,000 Generation (dispatched capacity), kWh = 11,160,000 Non-compliant hours, h = 5 WESM Rate, PhP per kWh = 4.00 PR Rate, PhP per kW per hour = 1.50 Variable Rate, PhP per kWh = 1.50 No. of Hours, h = 744 Undispatched Capacity Payment, PhP = 39,060,000.00 Incidental Energy Payment = 33,480,000.00 WESM Revenue = 44,640,000.00 Penalty (PhP) = 187,500.00 PR Payment (PhP) = 38,872,500.00 B. Secondary Reserve (SR) �� = �� ℎ� �� + �� − �� Where:

�� ℎ� �� = � �� ℎ� �� × *�� !"#

�� = $� �# % × �*�� ! + &��'��""( − )�*+��,��-�

If computed Incidental Energy < 0, set value of Incidental Energy payment at 0

Page 41 of 44

Scheduled Capacity (SC), kW = 50,000 Undispatched Capacity, kW = 1,000 Generation (dispatched capacity), kWh = 29,760,000 Non-compliant hours, h = 5 WESM Rate, PhP per kWh = 4.00 SR Rate, PhP per kW per hour = 2.25 Variable Rate, PhP per kWh = 1.50 No. of Hours, h = 744 Undispatched Capacity Payment, PhP = 1,674,000.00 Incidental Energy Payment = 111,600,000.00 WESM Revenue = 119,040,000.00 Penalty (PhP) = 281,250.00 SR Payment (PhP) = 1,392,750.00

C. Tertiary Reserve (TR) .�� = �� ℎ� �� + �� − �� Where:

�� ℎ� �� = � �� ℎ� �� × .�� !"#

�� = $� �# % × �.�� ! + &��'��""( − )�*+��,��-�

If computed Incidental Energy < 0, set value of Incidental Energy payment at 0 Scheduled Capacity (SC), kW = 50,000 Undispatched Capacity, kW = 40,000 Generation (dispatched capacity), kWh = 7,440.000 Non-compliant hours, h = 5 WESM Rate, PhP per kWh = 4.00 TR Rate, PhP per kW per hour = 1.25 Variable Rate, PhP per kWh = 1.50 No. of Hours, h = 744 Undispatched Capacity Payment, PhP = 37,200,000.00 Incidental Energy Payment = 20,460,000.00 WESM Revenue = 29,760,000.00 Penalty (PhP) = 156,250.00 TR Payment (PhP) = 37,043,750.00

D. Reactive Power Support Service (RS)

��*�� =� /*0# × ��*�� !1 − ��*��2#

Scheduled Quantity (SQ), kVAR = 20,000

Page 42 of 44

Rate, PhP per kVAR per hour = 4.00 No. of Hours, h = 8 Payment, PhP = 640,000.00 Penalty (PhP) = 40,000.00 RPS Payment (PhP) = 600,000.00

Note: For Reactive Power Support, the compensable kVAR is the reactive power provided outside of the required 0.85pf lagging and 0.90pf leading, but within the generating unit’s capability curve. E. Black Start Service (BS) (monthly payment per provider)

3*�� =� /4�# × 3*�� !1 − 3*��2#

Dispatched Capacity, kW = 100,000 Rate, PhP per kW per hour = 6.2185 No. of Hours, h = 12 Payment, PhP = 7,462,200.00 Penalty (PhP) = 1,041,666 BS Payment (PhP) = 6,420,534.00

Note: For Black Start Service, the sample computation is for those with ASPA approvals on a “per occurrence” payment basis. True cost of generation is paid only when the Black Start Service plant is dispatched to re-power the Grid.

Page 43 of 44

Attachment 6 – Tertiary Reserve Interruptible Load Certification Test

1.0 PURPOSE 1.1 To establish the guidelines that NGCP shall use to test the load to be contracted for

Tertiary Reserve - Interruptible Load that can be interrupted manually.

2.0 SCOPE 2.1 This procedure covers the Tertiary Reserve type of Ancillary Service that qualifies

Interruptible Load through manual load dropping to ensure the provision of capacity which is necessary to respond manually to unexpected loss of Generating Unit.

3.0 DEFINITIONS OF TERMS/ACRONYMS

3.1 Definition of Terms

3.1.1 Tertiary Reserve – the synchronized/unsynchronized generating capacity that is not scheduled for regular energy supply, PR or SR, or Interruptible Loads (IL) not scheduled for TR and that are readily available for dispatch in order to address the security and reliability of the Grid at any given interval.

3.1.2 Qualified Interruptible Load – A load which has been tested and certified as qualified by the System Operator under the provisions of this ASPP document, where only the Qualified Interruptible Loads are eligible to be scheduled as and receive payments for providing Ancillary Services.

3.2 Acronyms

3.2.1 TR – Tertiary Reserve 3.2.2 NCC – National Control Center

4.0 GENERAL REQUIREMENTS 4.1 The single line diagram of the load to be dropped which had been submitted to the

System Operation. 4.2 The load profile of the load being offered as Interruptible Load (Tertiary Reserve). 4.3 System at normal condition. 4.4 Approval from the National/Regional Control Center 7 (seven) days to actual date of

testing. 4.5 Utmost safety is a priority. Abort the test if the conditions will affect the normal

operation of the system.

5.0 REFERENCES

5.1 Ancillary Services Procurement Plan 5.2 Philippine Grid Code Amendment No. 2

Page 44 of 44

7.0 PROCEDURE

Activity Responsibility Details

Engineer - ASS Request NCC/ACC personnel regarding the test to be done.

Engineer - ASS Perform preliminary inspection and standard setting of measuring instruments.

Engineer - ASS

Connect test instrument e.g. PQ analyzer, to measure the load to be interrupted. Make sure that the power supply is off in connecting test instrument and proper grounding connection before powering up.

Load Control Room Operator / Engineer - ASS

Initiate activation of trip coil of designated circuit breaker remotely or manually.

Engineer - ASS Record the readings of the pick-up frequency and the corresponding interrupted load recorded in the PQ analyzer and/or in the digital meter.

START

1. Request Clearance from Control Center regarding testing of Interruptible Load by manual load dropping 7 (seven) days prior to actual date of testing.

2. Proceed to Interruptible Load manual load drop testing

3. Connect PQ analyzer to measure the load to be interrupted

4. Activate the trip coil of the designated circuit breaker within 30 mins. from receipt of instruction from NCC.

5. Record the activation time and quantity of load interrupted.

END

Documents

ANCILLARY SERVICES PROCUREMENT PLANerc.gov.ph/Files/Render/media/ERCCaseNo.2017-005RM-AnnexA.pdf · Units will provide Ancillary Services to implement the final Dispatch Schedule