(PDF) DeShazo, Gary · Gary DeShazo - CAISO (LSAG Chair) To All: On behalf of the California ISO, I am pleased to welcome you as a member of the 2008 LCR Study Advisory Group ("LSAG")

DeShazo, Gary

From: DeShazo, Gary

Sent: Wednesday, September 20, 2006 8:36 PM

To: Mara, Sue; Amirali, Ali; Chifong Thomas (E-mail); Tang, Bob; Tarplee, Gary; Caroline Winn (E-mail); Jaske, Mike; Flynn, Thomas R.; Braun, Tony; Waples, Scott; DeShazo, Gary

Cc: Doughty, Thomas; Dukes, Dana

Subject: CAISO LCR Study Advisory Group

Page 1 of 2

10/17/2006

Sue Mara – RTO Advisors Ali Amirali – LS Power Chifong Thomas – PG&E Bob Tang – City of Azusa Gary Tarplee – SCE (final selection pending) Carolyn Winn – SDG&E (final selection pending) Mike Jaske – CEC (final selection pending) Tom Flynn – CPUC (final selection pending) Tony Braun – Northern CAISO Municipal (final selection pending) WECC Reliability Subcommittee Representative (final selection pending) Gary DeShazo - CAISO (LSAG Chair) To All: On behalf of the California ISO, I am pleased to welcome you as a member of the 2008 LCR Study Advisory Group ("LSAG"). Over the coming couple of months, we will collaborate on a review of the assumptions and criteria for this important study. I want to thank you in advance for your investment of time and thought. As you know, over the last 18 months, the CAISO has been working with stakeholders to determine the locational capacity requirements across the California ISO Controlled Grid in a manner that is consistent with the California Public Utility Commission’s ("CPUC") implementation of Resource Adequacy. Earlier this year the CPUC adopted the CAISO's LCR results for 2007. At the same time, the CPUC indicated its desire for the CAISO to continue working with stakeholders towards preparing for the 2008 analysis which will need to begin in January 2007 in order to meet the CPUC's resource adequacy milestones. Commensurate with the CPUC's desire to look forward to 2008, the CAISO is forming the LSAG, a small group of subject matter experts representing a cross-section of stakeholder interests, to take an indepth look at the CAISO's 2007 LCR study assumptions, processes, and criteria and make recommendations for assumptions, processces, and criteria to be used for the 2008 analysis. In preparation for our inaugural meeting, I hope you will take a moment to review the attached draft charter for the group. It is our hope that the charter will help instill a common understanding of our group's mission and deliverables, which must be completed by the end of November. In consideration of the 2006 holiday season, completing our work in this timeframe should provide ample time for CAISO Staff to initiate the 2008 work in a timely manner. The details for our first meeting are as follows:

September 28, 2006 Location: California ISO, Building 110 Natomas Conference Room 151 Blue Ravine Road Folsom, CA 95630 Security considerations: Security badges can be picked up at building 101 which is where the CAISO Board Room is located.

Please RSVP your attendance at this meeting by sending an email to Dana Dukes at [emailprotected] or

by calling Dana at (916) 608-5715. Call me at any time with questions. We're looking forward to a robust and constructive discussion with you. Gary DeShazo

Director, Regional Transmission North (916) 608-5880

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10/17/2006

Draft Agenda LCR Study Advisory Group (LSAG) Meeting

September 28, 2006 10am – 4pm

Natomas Room California ISO

I. Introductions - All II. Arrangements & Support - DeShazo III. Review Agenda - All IV. LSAG Charter – DeShazo

A. Purpose of the Group 1. Advise 2. Aid

B. Representation and Expectations of Participants C. Objectives

1. Review and validate 2007 LCR study 2. Consensus on 2008 LCR Study Assumptions, processes, & criteria 3. Document LSAG Recommendations

D. Scope of Activities E. Group Comments - All

V. 2007 LCR Study Review - Micsa A. Base Cases B. Load Pockets C. Category B Contingencies D. Category C Contingencies E. Application of NERC/WECC Criteria

VI. Identify Action Items – Dukes VII. Establish Meeting Schedule and Locations – All VIII. Other Items - All IX. Adjourn

CAISO P&ID 9/28/2006

Brief Summary of Technical Issues from Comments Submitted to CPUC On CAISO 2007 LCR Study/Report

1) AReM

a) Probability of events 2) SCE

a) Allowance for operating procedures b) South of Lugo, Category D type disturbance

3) CCSF a) Load Pockets

4) Constellation Power a) Clarify qualifying capacity b) How are operating procedures accommodated in study

5) NCPA a) Did not allow load shedding for N-2 b) Probability of events c) Did not adjust system after first contingency

6) IEP a) Clarity on load pockets

7) PG&E a) Stable and consistent approaches to study b) Ambiguity in NERC/WECC standard; specifically, allowance of load

shedding c) Sub-area approach may cause over procurement d) Sierra – reliability or congestion issue e) Use of 5% threshold cost effective

8) DRA a) Clarity on N-1-1 versus N-2

9) Energy Producers & Users Coalition a) Probability of events

CAISO P&ID 9/28/2006

Charter - CAISO LCR Study Advisory Group (LSAG) September 5, 2006

Introduction In preparation for the 2008 Local Capacity Requirements (“LCR”) Study, and the recognized need for transparency and industry involvement, the CAISO shall form an LCR Study Advisory Group (“LSAG”). The LSAG shall evaluate, assist in any recommended refinement of, and comment on the study assumptions, processes and criteria to be used by the CAISO in the 2008 LCR Study. This effort must be completed by November 2006 in order to complete the 2008 LCR Study in a timeframe consistent with existing regulatory parameters. Mission and Purpose The LSAG shall be an ad hoc group of experts, meeting the criteria set forth below, representing identified segments of California’s electricity marketplace, formed and administered by the CAISO. The LSAG will:

I. Advise the CAISO Transmission Planning organization on the , assumptions, and study criteria for the 2008 LCR Study.

II. Aid the CAISO in developing the study plan and support the development of communications regarding the 2008 LCR Study to other market participants.

Anticipated Scope of Activities Within the LSAG time horizon and the 2008 LCR Study deadlines, as noted above, the LSAG will:

I. Review and provide input on the CAISO’s 2008 LCR Study plans, documents and materials, including suggested refinements, prior to publication to the broader stakeholder audience.

II. Propose methods to advance collaboration between CAISO and market participants on the LCR Study.

III. Discuss issues related to the LCR study, which are brought by CAISO and LSAG participants, and formulate options for resolution.

IV. Produce, if necessary or desired, comments on the final CAISO LCR Study assumptions and criteria.

Participant Representation LSAG participants shall be required to possess specific training and/or experience in at least two of the following areas:

1. Transmission planning 2. Performing powerflow modeling 3. Grid operations

4. WECC/NERC reliability criteria

Such individuals must provide to the CAISO a resume/curriculum vitae verifying satisfaction of the foregoing eligibility standards. The CAISO will make a reasonable effort to select eligible individuals from, or representing, the following regulatory entities, market participants or industry segments:

1. California Public Utilities Commission 2. California Energy Commission 3. Western Electricity Coordinating Council 4. Pacific Gas and Electric Company 5. Southern California Edison Company 6. San Diego Gas & Electric Company 7. CAISO Control Area municipal or other local public utilities – North and South 8. Large end-use customers Small end-use customers 9. Electric Service Providers/Community Choice Aggregators 10. Generators

The CAISO will, therefore, select among identified and qualified individuals to form a broad-based advisory group consisting of at least eleven (11) participants. The CAISO’s selection shall be binding. Once selected, participation is name-specific and is not assignable or delegable. All efforts will be made to coordinate schedules to maximize participation and the opportunity to participate by telephone will be provided for all LSAG meetings as noted below. Duration and Term LSAG is expected to remain active through November 2006, or at such time that the study assumptions are complete for the 2008 LCR Study, whichever comes first. Group Operations / logistics LSAG will meet between September and November 2006. Meetings will be in face-to-face or conference call formats.

I. CAISO will develop and publish a schedule of LSAG meetings from September through November 2006.

II. CAISO will develop and publish LSAG meeting agendas and supporting documents approximately one week prior to each meeting to the extent possible.

III. CAISO will provide telephone dial-in capability for all LSAG meetings. IV. In addition to reviewing CAISO-initiated issues, each meeting will include time for

LSAG members to introduce issues for discussion. V. CAISO staff will chair and participate in the LSAG meetings.

VI. CAISO will track issues and action items identified in the LSAG meetings, and will post any materials produced in response to such issues or action items to its web site.

Armie Perez/Gary DeShazo, CAISO P&ID 0

California Independent System

Operator

• Power Flow StudiesSimulation of snapshot steady-state system conditions. Compared results against reliability criteria to determine criteria violations.

Generator OutputGenerator Capability

Reliability

N-1N-2…

Transmission line dataTransformer dataOther equipments

Amount and location of load

California ISO

2007 LOCAL CAPACITY TECHNICAL

ANALYSIS

REPORT AND STUDY RESULTS

Corrected Version July 18, 2006

Local Capacity Technical Analysis Overview and Study Results

I. Executive Summary

At the February 3, 2006 prehearing conference in Docket R.05-12-013

(Rulemaking to Consider Refinements to and Further Development of the

Commission’s Resource Adequacy Requirements Program), the California

Independent System Operator Corporation (“CAISO”) advised the California Public

Utilities Commission (“CPUC”) that the Local Capacity Requirement (“LCR”) results

of its 2007 local capacity technical analysis could be made available within eight

weeks after the development of the input assumptions for the study. Following a

meet and confer process, Administrative Law Judge Wetzell adopted proposed

study assumptions. These assumptions have been incorporated into this “Local

Capacity Technical Analysis Study (“2007 LCR Study”), as discussed below. The

CAISO has now completed its analysis and therefore provides this 2007 LCR Study

to describe the final LCR results and the methodology and criteria used to obtain

those results.

This Report provides a description of the 2007 LCR Study objectives, inputs,

methodologies and assumptions, and the important policy considerations that are

presented by the study results. Specifically, as requested by the Stakeholders and

approved by the CPUC, the CAISO has conducted the study to produce local area

capacity requirements necessary to achieve three levels of service reliability. These

levels of service reliability, which are driven by the transmission grid operating

standards to which the CAISO must comply, are set forth on the following table1:

1 This comparison table is explained in detail at Section IV. below. The reader should be aware that the deficiencies identified for certain local areas are driven by capacity requirements in sub-area load pockets discussed at IV.B.

Local Requirements Comparison

* Generation deficient areas (or with sub-area that are deficient) – deficiency included in LCR ** The North Coast/North Bay and Greater Bay Area requirements would have been higher by 80 and 570 MW respectively, however two new operating procedures have been received, validated and implemented by PG&E and the CAISO.

The term “Qualifying Capacity” used in this report represents the “Gross

Qualifying Capacity” (as of 1/12/2006) and it may be slightly higher, for certain

generators, then the “Net Qualifying Capacity” as presented in the official list stored

at:

http://www.caiso.com/1796/179694f65b9f0.xls

The difference between the terms “Qualifying Capacity” and “Net Qualifying

Capacity” is that certain units have associated plant load and thus, the “Net

Qualifying Capacity” represents the output from the unit after the plant load has been

subtracted. However, the LCR Study incorporates the plant load from these units

into the “total load” calculation.

The first column, “Qualifying Capacity”, reflects two sets of generation. The

first set is comprised of generation that would normally be expected to be on-line

such as Municipal generation and Regulatory Must-take generation (State, Federal,

QFs and nuclear units). The second set is “market” generation. The second column,

Qualifying Capacity 2007 LCR Requirement Based on Category B

Option 1

2007 LCR Requirement Based on Category C with

operating procedure Option 2

2006 Total LCR Req.

Local Area Name

QF/ Muni (MW)

Market (MW)

Total (MW)

Existing Capacity Needed

Deficiency Total (MW)

Existing Capacity Needed

Deficiency Total (MW) (MW)

Humboldt 73 133 206 202 0 202 202 0 202 162 North Coast / North Bay 158 861 1019 582** 0 582** 582** 0 582** 658

Sierra 1072 776 1848 1833 205 2038 1833 328 2161 1770*

Stockton 314 257 571 432 0 432 536 53 589 440*

Greater Bay 1314 5231 6545 4771 0 4771 4771** 0 4771** 6009 Greater Fresno 575 2337 2912 2115 0 2115 2151 68 2219 2837 *

Kern 978 31 1009 554 0 554 769 17 786 797* LA Basin 3510 7012 10522 8843 0 8843 8843 0 8843 8127 San Diego 191 2741 2932 2781 0 2781 2781 0 2781 2620 Total 8185 19379 27564 22113 205 22318 22468 466 22934 23420

http://www.caiso.com/1796/179694f65b9f0.xls

“2007 LCR Requirement Based on Category B” identifies the local capacity

requirements, and deficiencies that must be addressed, in order to achieve a service

reliability level based on Performance Criteria- Category B (Option 1, discussed in

Section II.C of this Report). The third column, “2007 LCR Requirement Based on

Category C with Operating Procedure”, sets forth the local capacity requirements,

and deficiencies that must be addressed, necessary to attain a service reliability

level based on Performance Criteria-Category C with operational solutions (Option

2).

The highest service reliability level, based on Performance Criteria-Category

C without non-generational solutions to address operating deficiencies (Option 3),

can be determined from the table by adding 80 MW to the local capacity

requirements for the North Coast/North Bay area (thus raising total 2007 LCR

requirements by 80 MW). This exercise removes the new operating procedure

provided by PG&E from the analysis in compliance with the Category C reliability

standard that relies solely on generation to address identified capacity deficiencies.

As shown on the table above, the study results have important public policy

implications. These study results indicate 3 levels of capacity that are necessary to

have sufficient capacity in support of 3 levels of service reliability. The reader should

appreciate that the differences in levels of capacity have direct implications to the

costs and expected levels of reliability that are achieved for customers located within

the local areas. Thus, option 1 (performance level B) has a lower level of capacity

required and will therefore have an expected lower level of reliability because less

capacity is available to the CAISO. Similarly, the operational solutions underlying

option 2 (performance level C) provide for less procurement of capacity than option

3 by placing load in the mix of solutions that the CAISO will use to respond to

contingencies. This approach may be appropriate where all outages are expected to

have short-term affects on the transmission system. Yet, long duration outages

would potentially subject load to extended outages. Option 3 also NERC

performance level C, results provide the quantity of capacity that would give the

CAISO a full set of capacity to respond to contingencies. This level effectively

reserves the load based operational solutions for major emergencies or

contingencies that are not considered in the study criteria and therefore results in an

expected higher level of service reliability than the two alternate options.

Public policy decision-makers must choose the appropriate level of service

reliability. The information provided in the 2007 LCR Study, including the CAISO’s

recommendations found at Section II.E. below, can assist with this choice.

II. Overview of The Study: Inputs, Outputs and Options

A. Objectives

Similar to the 2006 Local Capacity Technical Analysis (“2006 LCR Study”)2,

the purpose of the2007 LCR Study is to identify specific areas within the CAISO

Controlled Grid that have local reliability problems and to determine the generation

capacity (MW) that would be required to mitigate these local reliability problems.

However, based on input from market participants and at the direction of the CPUC,

the 2007 LCR Study identifies different levels of local capacity that correspond to

separate performance/reliability criteria related to grid robustness under which the

CAISO must plan and operate the grid. This additional information is intended to

allow the CPUC to affect the expected level of service reliability that customers of

jurisdictional LSEs will receive by dictating the appropriate amount of local capacity

that must be procured. In so doing, the CPUC should endeavor to make a decision

that seeks to find the appropriate balance between a desired level of service

reliability and the cost of installed capacity. The details of the 2007 LCR study, set

forth in the following sections, will facilitate the CPUC’s ability to make this important

decision.

2 The 2006 LCR Study (Locational Capacity Technical Analysis: Overview of Study Report and Final Results) dated September 23, 2005 was submitted to the CPUC as part of the CAISO’s Motion to Augment the Record Regarding Resource Adequacy Phase 2 in R.04-04-003. An Addendum to the 2006 LCR Study was submitted on January 31, 2006. These documents can be found on the CAISO website at: http://www.caiso.com/1788/178883551f690.html and http://www.caiso.com/docs/2004/10/04/2004100410354511659.html

B. Key Study Assumptions

1. Inputs and Methodology

The CPUC directed the CAISO, respondents, and other interested parties to

meet and confer with the objective of identifying not more than three alternative sets

of input assumptions the CAISO would incorporate into the 2007 LCR Study. The

meet and confer session was held on February 17, 2006 and, as noted above, the

agreed-upon input scenarios were submitted by the CAISO on February 22, 2006.

An errata to the February 22 filing was submitted on March 10, 2006. The following

table sets forth a summary of the approved inputs and methodology that have been

used in the 2007 LCR Study:

Summary Table of Inputs and Methodology Used in 2007 LCR Study:

Issue: HOW INCORPORATED INTO THE 2007 LCR STUDY:

Input Assumptions:

• Transmission System Configuration

The existing transmission system has been modeled, including all projects operational on or before June 1, 2007 and all other feasible operational solutions brought forth by the PTOs and as agreed to by the CAISO.

• Generation Modeled The existing generation resources has been modeled and also includes all projects that will be on-line and commercial on or before June 1, 2007

• Load Forecast Uses a 1-in-10 year summer peak load forecast

Methodology:

• Maximize Import Capability Import capability into the load pocket has been maximized, thus minimizing the generation required in the load pocket to meet applicable reliability requirements.

• QF/Nuclear/State/Federal Units

Regulatory Must-take and similarly situated units like QF/Nuclear/State/Federal resources have been modeled on-line at historical output values for purposes of the 2007 LCR Study.

• Maintaining Path Flows Path flows have been maintained below all established path ratings into the load pockets, including the 500 kV. For clarification, given the existing transmission system configuration, the only 500 kV path that flows directly into a load pocket and will, therefore, be considered in the 2007 LCR Study is the South of Lugo transfer path flowing into the LA Basin.

Performance Criteria:

• Performance Level B & C, including incorporation of PTO operational solutions

The 2007 LCR Study is being published based on Performance Level B and Performance Level C criterion, yielding the low and high range LCR scenarios. In addition, the CAISO will incorporate all new projects and other feasible and CAISO-approved operational solutions brought forth by the PTOs that can be operational on or before June 1, 2007. Any such solutions that can reduce the need for procurement to meet the Performance Level C criteria will be incorporated into the LCR Study and the resulting LCR published for this third scenario.

Load Pocket:

• Fixed Boundary, including limited reference to published effectiveness factors

The 2007 LCR Study has been produced based on load pockets defined by a fixed boundary. The CAISO was initially planning to publish the effectiveness factors of the generating resources within the defined load pocket as well as the effectiveness factors of the generating resources residing outside the load pocket that had a relative effectiveness factor of no less than 5% or affect the flow on the limiting equipment by more than 5% of the equipment’s applicable rating. . However, after subsequent discussions with the Commission and stakeholders, and given the comments in the CPUC Staff Report regarding the limited usefulness of effectiveness factors, the CAISO plans to only publish effectiveness factors where they are useful in facilitating procurement where excess capacity exists within a load pocket. If stakeholders want additional effectiveness factor published, the CAISO will defer to the Commission as to what further effectiveness factor data it would like the CAISO to publish.

Further details regarding the 2007 LCR Study methodology and assumptions

are provided in Section III, below.

2. Operating Requirements

As was done in the 2006 LCR Study, this study incorporates specific

operating requirements, needed in order to prevent voltage collapse or transient

instability for the loss of a single transmission element (”N-1”) followed by system

readjustment and the loss of two transmission lines (common mode failure)3. In

addition, the LCR Study addresses contingencies where the system suffers the loss

of a single transmission element (”N-1”), the system is readjusted and then the loss

of an additional transmission element (N-1-1). As reflected in Table 2, the capacity

in columns two (Category B) and three (Category C) are identical in at least four of

the local areas. This occurs because the capacity necessary to prevent voltage

collapse or transient instability for the loss of a single transmission element (N-1) is

the same as that necessary for the N-1-1 scenario.

Consistent with NERC standards, after the second N-1 or immediately after

the common mode failure load shedding is allowed as long as all criteria (thermal,

voltage, transient, reactive margin) are respected. The CAISO planning criteria

generally allows for load shedding for the double contingencies. However, the

CAISO has, consistent with its Tariff, conducted planning studies that maintain the

level of reliability that existed prior to its formation. This is referred in the CAISO

Tariff as “Local Reliability Criteria,” which, along with NERC Planning Standards

discussed below, form the CAISO’s “Applicable Reliability Criteria” The CAISO is

under an obligation to implement Local Reliability Criteria, unless modified pursuant

to agreement with the relevant Participating Transmission Owner (“PTO”). As such,

to the extent a PTO’s pre-CAISO standards did not allow for load shedding for

common corridor and/or double circuit tower line outages, the CAISO has

maintained that practice to assure that the level of reliability that prevailed before the

CAISO was formed would be maintained and the CAISO remains in compliance with

its obligations.

3 These failures include a double circuit tower and the loss of two 500kv lines that are located in the same corridor.

C. Grid Reliability and Service Reliability

The 2007 LCR Study is intended to provide the CPUC with the “tools” needed

to make the important threshold policy decision as to the desired level of service

reliability within the CAISO Control Area, ultimately establishing the appropriate

amount of local generation capacity CPUC jurisdictional LSEs must procure. The

options produced by the study for consideration by the CPUC are discussed in

further detail in this overview section of the report, and also in the technical

discussion of the study itself. However, to assist the CPUC in analyzing the study

results and the options that are being presented, it is important that the CPUC and

other parties understand how the CAISO distinguishes “service reliability” from “grid

reliability” and where the respective CAISO/CPUC responsibilities lie. Both service

and grid reliability form the basis of the reliability standards consumers within the

CAISO Control Area will receive.

1. Grid Reliability

Service reliability builds from grid reliability because grid reliability is reflected

in the planning standards of the Western Electricity Coordinating Council (“WECC”)

that incorporate standards set by the North American Electric Reliability Council

(“NERC”) (collectively “NERC Planning Standards”). The NERC Planning Standards

primarily apply to the bulk, interconnected electric system in the Western United

States and are intended to address the reality that within an integrated network,

whatever one control area does can affect the reliability of other control areas.

Consistent with the mandatory nature of the NERC Planning Standards, the CAISO

is under a statutory obligation to ensure efficient use and reliable operation of the

transmission grid consistent with achievement of the NERC Planning Standards.4

The CAISO is further under an obligation, pursuant to its FERC-approved

Transmission Control Agreement, to secure compliance with all “Applicable

Reliability Criteria.” Applicable Reliability Criteria consists of the NERC Planning

Standards as well as reliability criteria adopted by the CAISO, in consultation with

4 Pub. Utilities Code § 345

the CAISO’s Participating Transmission Owners (“PTOs”), which affect a PTO’s

individual system.

The NERC Planning Standards define reliability on interconnected bulk

electric systems using the terms “adequacy” and “security.” “Adequacy” is the ability

of the electric systems to supply the aggregate electrical demand and energy

requirements of their customers at all times, taking into account physical

characteristics of the transmission system such as transmission ratings and scheduled and reasonably expected unscheduled outages of system elements.

“Security” is the ability of the electric systems to withstand sudden disturbances such

as electric short circuits or unanticipated loss of system elements. The NERC

Planning Standards are organized by Performance Categories. For instance, one

category could require that the grid operator not only ensure grid integrity is

maintained under certain adverse system conditions, e.g., security, but also that all

customers continue to receive electric supply to meet demand, e.g., adequacy. In

that case, grid reliability and service reliability would overlap. But there are other

levels of performance where security can be maintained without ensuring adequacy.

Here, it would be up to the regulatory agency of service reliability, i.e. the CPUC, to

determine the appropriate level of service reliability under the system conditions

defined by the differing levels of NERC planning standards.

Given the foregoing, one of the ambiguities identified in the recent CPUC

workshops is the fact that several performance categories make up the NERC

Planning Standards and, therefore, Applicable Reliability Criteria. The various

parties perceived this as potentially permitting the CAISO to procure generation, in

its backstop role, to satisfy all performance categories. Rather, the CAISO believes

it is the role of the CPUC to determine the level of service reliability it wishes to

establish for the ratepayers. To further addresses this concern, it is important to

again describe the Performance Categories, which are critical to understanding how

the CPUC and CAISO can work together.

a. Performance Criteria As set forth on the Summary Table of Inputs and Methodology, the 2007 LCR

is based on NERC Performance Level B and Performance Level C criterion, yielding

the low and high range LCR scenarios. These Performance Levels can be

described as follows:

i. Performance Criteria- Category B

Category B describes the system performance that is expected following the

loss of a single transmission element, such as a transmission circuit, a generator, or

a transformer.

Category B system performance requires that all thermal and voltage limits

must be within their “Applicable Rating,” which, in this case, are the emergency

ratings as generally determined by the PTO or facility owner. Applicable Rating

includes a temporal element such that emergency ratings can only be maintained for

a certain duration. Under this category, load cannot be shed in order to assure the

Applicable Ratings are met and that facilities are returned to normal ratings when

either the element that was lost is returned to service or system adjustments are

made within the appropriate time limits.

However, the NERC Standards require system operators to “look forward” to

make sure they safely prepare for the “next” N-1 following the loss of the “first” N-1

(stay within Applicable Ratings after the “next” N-1). This is commonly referred to as

N-1-1. Because it is assumed that some time exists between the “first” and “next”

element losses, operating personnel may make any reasonable and feasible

adjustments to the system to prepare for the loss of the second element, including,

pre-contingency load-shedding, dispatching generation, moving load from one

substation to another to reduce equipment loading, dispatching operating personnel

to specific station locations to manually adjust load from the substation site, or

installing a “Special Protection Scheme” that would remove pre-identified load from

service upon the loss of the “next “ element.5

ii. Performance Criteria- Category C

Category C describes system performance that is expected following the loss

of two or more system elements. This loss of two elements is generally expected to

happen simultaneously, referred to as N-2. It should be noted that once the “next”

element is lost after the first contingency, as discussed above under the

Performance Criteria B, N-1-1 scenario, the event is effectively a Category C. As

noted above, depending on system design and expected system impacts, the

controlled interruption of supply to customers (load shedding), the removal from

service of certain generators and curtailment of exports may be utilized to maintain

grid “security.”

2. Service Reliability

The CAISO is responsible for grid reliability in accordance with the NERC

performance criteria described above. However, grid reliability can be maintained at

service reliability levels that may be unacceptable to the CPUC and end user

customers. The 2007 LCR Study presents the CPUC with relevant information to

select a level of service reliability that also fulfills grid reliability. Specifically, the

study specifies varying generation capacity levels for each local capacity area based

on Performance criteria- Categories B and C, with the inclusion of suitable non-

generation solutions raised by the PTOs to address contingency conditions as

described under Performance Criteria- Category C.

5 A Special Protection Scheme is typically proposed as an operational solution that does not require additional generation and permits operators to effectively prepare for the next event as well as ensure security should the next event occur. However, these systems have their own risks, which limit the extent to which they could be deployed as a solution for grid reliability augmentation. While they provide the value of protecting against the next event without the need for pre-contingency load shedding, they add points of potential failure to the transmission network. This increases the potential for load interruptions because sometimes these systems will operate when not required and other times they will not operate when needed.

As shown by the study results, where the NERC Planning Standards do not

allow for load shedding, grid reliability and service reliability are the same and

establish a minimum level of capacity needed to meet the CAISO’s statutory

obligation.6 Where it is not possible to develop operating solutions to ensure

“controlled” interruption of service, in these cases generation will also be required to

meet Applicable Reliability Criteria to avoid the potential of load shedding in

anticipation of a contingency. Where feasible operational solutions and/or

generation procurement amounts affect the level of service to customers, service

reliability is implicated and different levels of service reliability may be possible.

D. The Three Options Presented By The 2007 LCR Study

The 2007 LCR study sets forth different solution “options” with varying ranges

of potential service reliability consistent with CAISO’s Applicable Reliability Criteria:

1. Option 1- Meet Performance Criteria Category B

Option 1 is a service reliability level that reflects generation capacity that must

be available to comply with reliability standards for NERC Category B given that load

cannot be removed to meet this performance standard under Applicable Reliability

Criteria. However, this capacity amount implicitly relies on load interruption as the

only means of meeting any Applicable Reliability Criteria that is beyond the loss of a

single transmission element (N-1). These situations will likely require substantial

load interruptions in order to maintain system continuity and alleviate equipment

overloads including load interruptions prior to the actual occurrence of the second

contingency.7

6 The NERC Planning Standards reflect a “deterministic” analysis that captures the “robustness” of the grid. In many NERC subregions, service reliability is understood as the probability of disconnecting firm load due to a resource deficiency. Control areas in the Western Electricity Coordinating Council, including the CAISO, do not currently have sufficient information to apply a probabilistic reliability analysis to transmission or planning studies. However, the CAISO has consistently recommended that the CPUC move to a loss of load probability approach as a means by which to consider alternative solutions while still planning to a desired level of service reliability. 7 This potential for pre-contingency load shedding also occurs because real time operators must prepare for the loss of a common mode N-2 at all times.

2. Option 2- Meet Performance Criteria Category C and Incorporate Suitable Operational Solutions

Option 2 is a service reliability level that reflects generation capacity that is

needed to readjust the system to prepare for the loss of a second transmission

element (N-1-1) using generation capacity after considering all reasonable and

feasible operating solutions (involving customer load interruption) developed and

approved by the CAISO, in consultation with the PTOs. Under this option, there is no

expected load interruption to end-use customers as the CAISO operators prepare for

the second contingency. However, the customer load will be interrupted in the event

the second contingency occurs.

3. Option 3- Meet Performance Criteria Category C through

Pure Procurement

Option 3 is a service reliability level that reflects generation capacity that is

needed to readjust the system to prepare for the loss of a second transmission

element (N-1-1) using generation capacity only. No load based operational solutions

are incorporated into this scenario. Therefore, this results in a “pure capacity”

procurement scenario.

E. The CPUC’s Responsibilities and The CAISO’s Recommendation

The CPUC is responsible for determination of the appropriate level of service

reliability to end-use customers within each CAISO-identified local capacity area.

The CPUC may meet this responsibility by exercising its jurisdiction over load

serving entities to compel procurement of generation or demand resources to meet

the option selected. The CPUC may also wish to allow the load serving entity to

choose planned or controlled load interruption options.8 The CPUC should impose

appropriate penalties for LSEs that fail to comply with the procurement levels that

are necessary to meet its established applicable reliability criteria standard. Finally,

in its determination of an acceptable service reliability level, the CPUC should

8 However, such automatic load shedding schemes or operating procedures implementing manual load shedding options must be acceptable to the CAISO, i.e., the load to be shed is demonstrable, verifiable, and appropriately dispatchable.

explicitly understand the implications associated with contingent events as well as

the potential that customers will receive different levels of service reliability based on

the service reliability level selected for each local capacity area.

As the grid operator, the CAISO recommends that Option 2 be selected as

the service reliability standard. Option 2 identifies a potential service reliability that

reflects generation capacity set forth in (2) above, adjusted for any feasible operating

solution identified by a PTO prior to the study and approved by the CAISO. On a

day-to-day basis the CAISO has traditionally operated the network based on the N-

1-1 contingency, with operating solutions developed with the PTOs. Should the

CPUC choose Option 2, and to the extent a load shedding solution proposed by a

PTO is isolated solely in the service territory of a CPUC load serving entity, the

CAISO has indicated the appropriateness of such operating procedure to the CPUC

in this study.

III. Assumption Details: How the Study was Conducted

A. System Planning Criteria

The following table provides a comparison of system planning criteria, based

on the NERC performance standards, used in the study:

Table 1: Criteria Comparison

Contingency Component(s) ISO Grid Planning Criteria

Existing RMR

Criteria

Locational Capacity Criteria

A – No Contingencies X X X

B – Loss of a single element 1. Generator (G-1) 2. Transmission Circuit (L-1) 3. Transformer (T-1) 4. Single Pole (dc) Line 5. G-1 system readjusted L-1

X X X X

X X X2 X X

X1 X1

X1,2 X1 X

C – Loss of two or more elements 1. Bus Section 2. Breaker (failure or internal fault) 3. L-1 system readjusted G-1 3. G-1 system readjusted T-1 or T-1 system readjusted G-1 3. L-1 system readjusted T-1 or T-1 system readjusted L-1 3. G-1 system readjusted G-1 3. L-1 system readjusted L-1 3. T-1 system readjusted T-1 4. Bipolar (dc) Line 5. Two circuits (Common Mode) L-2 6. SLG fault (stuck breaker or protection failure) for G-1 7. SLG fault (stuck breaker or protection failure) for L-1 8. SLG fault (stuck breaker or protection failure) for T-1 9. SLG fault (stuck breaker or protection failure) for Bus section WECC-S3. Two generators (Common Mode) G-2

X X X X X X X X X X X X X X X3

X X X X X

X X

D – Extreme event – loss of two or more elements Any B1-4 system readjusted (Common Mode) L-2 All other extreme combinations D1-14.

X4 X4

1 System must be able to readjust to normal limits. 2 A thermal or voltage criterion violation resulting from a transformer outage may not be cause for a local area reliability requirement if the violation is considered marginal (e.g. acceptable loss of facility life or low voltage), otherwise, such a violation will necessitate creation of a requirement. 3 Evaluate for risks and consequence, per NERC standards. No voltage collapse or dynamic instability allowed. 4 Evaluate for risks and consequence, per NERC standards.

A significant number of simulations were run to determine the most critical

contingencies within each Local Capacity Area. Using power flow, post-transient

load flow, and stability assessment tools, the system performance results of all the

contingencies that were studied were measured against the system performance

requirements defined by the criteria shown in Table 1. Where the specific system

performance requirements were not met, generation was adjusted such that the

minimum amount of generation required to meet the criteria was determined in the

Local Capacity Area. The following describes how the criteria were tested for the

specific type of analysis performed.

1. Power Flow Assessment:

Contingencies Thermal Criteria3 Voltage Criteria4 Generating unit 1, 6 Applicable Rating Applicable Rating Transmission line 1, 6 Applicable Rating Applicable Rating Transformer 1, 6 Applicable Rating5 Applicable Rating5 (G-1)(L-1) 2, 6 Applicable Rating Applicable Rating Overlapping 6, 7 Applicable Rating Applicable Rating

1 All single contingency outages (i.e. generating unit, transmission line or transformer) will be simulated on Participating Transmission Owners’ local area systems.

2 Key generating unit out, system readjusted, followed by a line outage. This over-lapping outage is considered a single contingency within the ISO Grid Planning Criteria. Therefore, load dropping for an overlapping G-1, L-1 scenario is not permitted.

3 Applicable Rating – Based on ISO Transmission Register or facility upgrade plans.

4 Applicable Rating – ISO Grid Planning Criteria or facility owner criteria as appropriate.

5 A thermal or voltage criterion violation resulting from a transformer outage may not be cause for a local area reliability requirement if the violation is considered marginal (e.g. acceptable loss of facility life or low voltage), otherwise, such a violation will necessitate creation of a requirement.

6 Following the first contingency (N-1), the generation must be sufficient to allow the operators to bring the system back to within acceptable (normal) operating range (voltage and loading) and/or appropriate OTC following the studied outage conditions.

7 During normal operation or following the first contingency (N-1), the generation must be sufficient to allow the operators to prepare for the next worst N-1 or common mode N-2 without pre-contingency interruptible or firm load shedding. SPS/RAS/Safety Nets may be utilized to satisfy the criteria after the second N-1 or common mode N-2 except if the problem is of a thermal nature such that short-term ratings could be utilized to provide the operators time to shed either interruptible or firm load. T-2s (two transformer bank outages) would be excluded from the criteria.

2. Post Transient Load Flow Assessment:

Contingencies Reactive Margin Criteria 2 Selected 1 Applicable Rating

1 If power flow results indicate significant low voltages for a given power flow contingency, simulate that outage using the post transient load flow program. The post-transient assessment will develop appropriate Q/V and/or P/V curves.

2 Applicable Rating – positive margin based on the higher of imports or load increase by 5% for N-1 contingencies, and 2.5% for N-2 contingencies.

3. Stability Assessment:

Contingencies Stability Criteria 2 Selected 1 Applicable Rating

1 Base on historical information, engineering judgment and/or if power flow or

post transient study results indicate significant low voltages or marginal reactive margin for a given contingency.

2 Applicable Rating – ISO Grid Planning Criteria or facility owner criteria as appropriate.

B. Methodology for Determining Zonal Requirements

A key part of the CAISO’s study for determining capacity requirements in

transmission-constrained areas includes zonal requirements to ensure that

sufficient generation capacity (in MWs) exists within each large zone so that

transmission constraints between zones do not threaten reliability. The analysis of

zonal requirements was discussed in the CPUC workshops and the 2006 Local

Capacity Technical Analysis (page 5), but the methodology for determining these

zonal requirements was not explained in detail.

The CAISO’s methodology for determining these zonal requirements is

designed so the operating reserves within each zone meet the WECC Minimum

Operating Reliability Criteria (MORC) for operating reserves.9

9 MORC states “Prudent operating judgment shall be exercised in distributing operating reserve, taking into account effective use of capacity in an emergency, time required to be effective, transmission limitations, and local area requirements.”

The determination of these zonal requirements is dependent upon key assumptions:

• Forecasted Load: Consistent with CAISO Planning Standards, the CAISO proposes a forecasted zonal load level that represents the 1-in-5-year peak conditions (more specifically the zonal area “coincident” peak.) For future studies the CAISO expects to use the CEC’s 1-in-5 year peak load forecasts.

• Import Capability: the maximum MW amount that is assumed can be

imported into a zone. This can be calculated based on the maximum historical imports into a zone, plus the anticipated increase in import capability due to transmission upgrades in effect for the time period being analyzed. This includes capacity from outside the CAISO Control Area and capacity between the zones, e.g. Path 26.

• Outages: the amount of generation that may be unavailable within a

zone due to unforeseen circ*mstances that require immediate maintenance. Assuming a peak load, this assumption would encompass forced outages as well as a very small amount of planned outages.

• Recovery from a Single Worst Contingency: enough operating

reserve to recover from the most severe single contingency without relying on firm load shedding. This total reserve capacity is based on the set of assumptions for peak load conditions. Existing industry standards do not permit shedding firm load to address a single contingency.

The zonal requirement (i.e., the amount of MWs needed within each region) is

determined simply by calculating the sum of the operating reserves for recovery from

a single worst contingency, the historical outage data, and the 1-in-5-year peak

forecast, subtracted by the import capability:

1 in 5 zonal Load forecast + Historical outage data + Recovery from single worst contingency – Import Capability = Zonal Requirement

Zonal requirements define the amount of generation (in MWs) that should

exist within a region to ensure the system’s ability to withstand a single worst

contingency. The CAISO should focus on the 500kV system only between three

major zones: NP15, NP15+ZP26, and south of Path 26 (SP26.) These are

historically defined regions of the CAISO Controlled Grid where inter-zonal

transmission constraints have been prone to deficiencies. Generation within all the

local areas within these zones would count toward meeting a zonal requirement.

C. Load Forecast

1. System Forecast

The load forecast at the system as well as PTO levels originates from

California Energy Commission (CEC). This most recent CEC forecast is then

distributed across the entire system, down to the local area, division and substation

level. PTO’s use an econometric equation to forecast the system load. The

predominant parameters affecting the system load are (1) number of households, (2)

economic activity (gross metropolitan products, GMP), (3) temperature and (4)

increased energy efficiency and distributed generation programs.

2. Base Case Load Development Method

The method used to develop the base case loads is a melding process that

extracts, adjusts and modifies the information from the system, distribution and muni

forecasts. The melding process consists of two parts. Part 1 deals with the PTO

load. Part 2 deals with the muni load. There may be small differences between the

methodologies used by each PTO to disaggregate the CEC load forecast to their

level of local area as well as bar-bus model; please refer to each PTO expansion

plan for additional details.

a. PTO Loads in Base Case

The methods used to determine the PTO loads are for the most part similar.

One part of the method deals with the determination of the division loads that would

meet the requirements of 1-in-5 or 1-in-10 system or area base cases and the other

part deals with the allocation of the division load to the transmission buses.

i. Determination of division loads

The annual division load is determined by summing the previous year division

load and the current division load growth. Thus the key steps are the determination

of the initial year division load and the annual load growth. The initial year for the

base case development method is based heavily on recorded data. The division load

growth in the system base case is determined in two steps. First, the total PTO load

growth for the year is determined, as the product of the PTO load and the load

growth rate from the system load forecast. Then this total PTO load growth is

allocated to the division, based on the relative magnitude of the load growths

projected for the divisions by the distribution planners. For example the 1-in-10 area

base case, the division load growth determined for the system base case is adjusted

to the 1-in-10 temperature using the load temperature relation determined from the

latest peak load and temperature data of the division.

ii. Allocation of division load to transmission bus

level

Since the base case loads are modeled at the various transmission buses,

the division loads developed would need to be allocated to those buses. The

allocation process is different depending on the load types. For the most part each

PTO’s classifies its loads into four types: conforming, non-conforming, self-

generation and generation-plant loads. Since the non-conforming and self-

generation loads are assumed to not vary with temperature, their magnitude would

be the same in the system or area base cases of the same year. The remaining load

(the total division load developed above, less the quantity of non-conforming and

self-generation load) is the conforming load. The remaining load would be allocated

to the transmission buses based on the relative magnitude of the distribution

forecast. The summation of all base case loads usually is higher then the load

forecast because some load like self-generation and generation-plant are load

behind the meter and they need to be modeled in the base cases, however for the

most part metered or aggregated data with telemetry is used to come up with the

load forecast.

b. Municipal Loads in Base Case The muni forecasts provided to the PTOs for the purposes of their base cases were

used for this study.

3. Comparison between the 1-in 5 and 1-in-10 local load forecast

As a rule of thumb, this difference translates into a corresponding one-for-one

reduction in the LCR -- (the MWs of capacity needed in that local area) -- provided

that the area constraint is driven by a thermal problem AND assuming that the load

and generation have roughly the same effectiveness factors.

The exact reduction in LCR results (using a less stringent 1-in-5-year instead

of the 1-in-10-year load forecast) could be different due to the load growth

characteristics specific to each local area. If the local area constraints are non-linear,

like voltage or dynamic problems, or if the effectiveness factors between the

generators and load within the same area are significantly different relative to the

worst thermal constraint, then the difference in LCR results will not mirror the

difference in load forecast.

Table 2: 2007 Local Area Load Forecast 1-in 5 vs 1-in-10

Peak Load (1 in 10) (MW)

Peak Load (1 in 5) (MW)

Difference (MW)

Difference (%)

Humboldt 197 196 1 0.5

North Coast/North Bay 1,513 1,475 38 2.5

Sierra 1,841 1,805 36 2.0

Stockton 1,267 1,252 15 1.2

Greater Bay 9,633 9,509 124 1.3

Greater Fresno 3,154 3,004 150 4.8

Kern 1,209 1,174 35 2.9

LA Basin 19,325 18,809 516 2.7

San Diego 4,742 4,610 134 2.8 Total 42,881* 41,834* 1,049 2.4

* Value shown only illustrative, since each local area peaks at a different time.

The peak load forecast is one key variable in the determination of the LCR

that meets the established criteria. In comparing the 1-in-5-year load analysis with

the 1-in-10-year standard, a general conclusion that could be drawn is that the

difference in required MWs for most of the local areas and sub-areas analyzed in

this report would not be huge. An analysis of each local area and the unique

contingencies within each area would be necessary to determine the exact

difference in LCR’s.

D. Power Flow Program Used in the LCR analysis

The LCR technical studies were conducted using General Electric’s Power

System Load Flow (GE PSLF) program version 15.2. This E PSLF program is

available directly from GE or through the Western System Electricity Council

(WECC) to any member.

The CAISO utilized the “2007 Heavy Summer 2A1” as the starting WECC

base case for the 2007 local area power flows used in the 2007 LCR studies. To

complete the local area component of this study, this base case was adjusted to

reflect the latest generation and transmission projects as well as the one-in-ten-year

peak load forecast for each local area as provided to the ISO by the Participating

Transmission Owners (“PTOs”).

Electronic contingency files provided by the PTOs were utilized to perform the

numerous contingencies required to identify the LCR needs. These contingency

files include remedial action and special protection schemes that are expected to be

in operation during 2007. An CAISO created EPCL (a GE programming language

contained within the GE PSLF package) routine was used to run the combination of

contingencies; however, other routines are available from WECC with the GE PSFL

package or can be developed by third parties to identify the most limiting

combination of contingencies requiring the highest amount of generation within the

local area to maintain power flows within applicable ratings. IV. Locational Capacity Requirement Study Results

A. Summary of Study Results

The LCR results reflect two sets of generation. The first set is comprised of

generation that would normally be expected to be on-line such as Municipal

generation and Regulatory Must-take generation (State, Federal, QFs and nuclear

units). The second set is “market” generation. Within this overview, LCR is defined

as the amount of generating capacity that is required within a Local Capacity Area to

reliably serve the load located within this area.

The results of the CAISO’s analysis are summarized in the following two tables. Table 3: Local Requirements Comparison

* Generation deficient areas (or with sub-area that are deficient) – deficiency included in LCR ** The North Coast/North Bay and Bay Area requirements would have been higher by 80 and 570 MW respectively, however two new operating procedures have been received, validated and implemented by PG&E and the CAISO.

The last column under “2007 LCR Requirement based on Category C with

operating solution” represents the MW of generation that the ISO is proposing to be

procured by all LSEs in local areas under the CPUC Local Capacity Requirements.

This column includes all units needed to maintain system reliability without the

potential for pre-contingency load shedding.

Qualifying Capacity 2007 LCR Requirement Based on Category B

Option 1

2007 LCR Requirement Based on Category C with

operating procedure Option 2

2006 Total LCR Req.

Local Area Name

QF/ Muni (MW)

Market (MW)

Total (MW)

Existing Capacity Needed

Deficiency Total (MW)

Existing Capacity Needed

Deficiency Total (MW) (MW)

Humboldt 73 133 206 202 0 202 202 0 202 162 North Coast / North Bay 158 861 1019 582** 0 582** 582** 0 582** 658

Sierra 1072 776 1848 1833 205 2038 1833 328 2161 1770*

Stockton 314 257 571 432 0 432 536 53 589 440*

Greater Bay 1314 5231 6545 4771 0 4771 4771** 0 4771** 6009 Greater Fresno 575 2337 2912 2115 0 2115 2151 68 2219 2837 *

Table 4: Local Capacity Requirements vs. Peak Load and Local Area Generation

2007 Total LCR

(MW)

Peak Load (1 in10) (MW)

2007 LCR as % of

Peak Load

Total Dependable Local Area

Generation (MW)

2007 LCR as % of Total Area Generation

Humboldt 202 197 103% 206 98%

North Coast/North Bay 582 1,513 38% 1,019 57%

Sierra 2,161 1,841 117% 1,848 117%**

Stockton 589 1,267 46% 571 103%**

Greater Bay 4,771 9,633 50% 6,545 73%

Greater Fresno 2,219 3,154 70% 2,912 76%**

Kern 786 1,209 65% 1,009 78%**

LA Basin 8,843 19,325 46% 10,522 84%

San Diego 2,781 4,742 59% 2,932 95% Total 22,934 42,881* 53%* 27,471 83%

* Value shown only illustrative, since each local area peaks at a different time. ** Generation deficient LCA (or with sub-area that are deficient) – deficiency included in LCR. Generator deficient area implies that in order to comply with the criteria, at summer peak, load must be shed immediately after the first contingency.

Table 3 shows how much of the local area load is dependent on local

generation and how much local generation needs to be available in order to reliably

(see LCR criteria) serve the load in those Local Capacity Areas. This table also

indicates where new transmission projects, new generation additions or demand

side management programs would be most useful in order to reduce the

dependency on existing (mostly old and inefficient) local area generation.

B. Summary of Results by Local Area

Each local area’s overall requirement is determined by also achieving each

sub-area requirement. Because these areas are a part of the interconnected electric

system, the total for each local area is not simply a summation of the sub-area

requirements. For example, some sub-areas may overlap and therefore the same

units have been counted toward both sub-area requirements. Of course some sub-

areas requirements are directly counted toward the total requirements of a bigger

local area or the overall area.

1. Humboldt Area

Area Definition The transmission tie lines into the area include:

1) Bridgeville-Cottonwood 115 kV line #1 2) Humboldt-Trinity 115 kV line #1 3) Willits-Garberville 60 kV line #1 4) Trinity-Maple Creek 60 kV line #1

The substations that delineate the Humboldt Area are:

1) Bridgeville 115 kV 2) Humboldt 115 kV 3) Kekawaka 60 kV 4) Ridge Cabin 60 kV

Total busload within the defined area: 191 MW with 6 MW of losses resulting in total load + losses of 197 MW. Total units and qualifying capacity available in this area: Gen Bus Gen Name ID Qualifying Capacity (MW)

31170 HMBOLDT1 1 51 31172 HMBOLDT2 1 52 31154 HUMBOLDT 1 15 31154 HUMBOLDT 2 15 31150 FAIRHAVN 1 17.2

31166 KEKAWAK 1 5.3 31158 LP SAMOA 1 25 31152 PAC.LUMB 2 12.5 31152 PAC.LUMB 1 12.5

Total 205.5 Critical Contingency Analysis Summary Humboldt overall:

The most critical contingency for the Humboldt area is the outage of the

Bridgeville-Cottonwood 115 kV line over-lapping with an outage of one Humboldt

Bay Power Plant. The local area limitation is low voltage and reactive power margin.

This multiple contingency establishes a Local Capacity Requirement of 202 MW

(includes 73 MW of QF/Selfgen generation) as the minimum capacity necessary for

reliable load serving capability within this area.

Effectiveness factors:

All units within this area have the same effectiveness factor. Units outside of this

area are not effective.

Humboldt Overall Requirements:

QF/Selfgen (MW)

Muni (MW)

Market (MW)

Max. Qualifying Capacity (MW)

Available generation 73 0 133 206 Existing Generation

Capacity Needed (MW) Deficiency

(MW) Total MW

Requirement Category B (Single)10 202 0 202 Category C (Multiple)11 202 0 202

10 A single contingency means that the system will be able the survive the loss of a single element, however the operators will not have any means (other then load drop) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by MORC. 11 Multiple contingencies means that the system will be able the survive the loss of a single element, and the operators will have enough generation (other operating procedures) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by MORC.

2. North Coast / North Bay Area Area Definition The North Coast/North Bay Area is composed of two sub-areas and the

generation requirements within them.

The transmission tie facilities coming into the Eagle Rock-Fulton sub-area are:

1) Fulton-Lakeville 230 kV line #1 2) Fulton-Ignacio 230kV line #1 3) Cortina 230/115 kV Transformer #1 4) Lakeville-Sonoma 115 kV line #1 5) Corona-Lakeville 115 kV line #1 6) Willits-Garberville 60 kV line #1

The substations that delineate the Eagle Rock-Fulton sub-area are:

1) Fulton 230 kV 2) Corona 115 kV 3) Sonoma 115 kV 4) Cortina 115 kV 5) Laytonville 60 kV

The transmission tie lines into the Lakeville sub-area are:

1) Vaca Dixon-Lakeville 230 kV line #1 2) Tulucay-Vaca Dixon 230 kV line #1 3) Lakeville-Sobrante 230 kV line #1 4) Ignacio-Sobrante 230 kV line #1 5) Ignacio-Fulton 230 kV line #1 6) Lakeville-Fulton 230 kV line #1 7) Lakeville-Corona 115 kV line #1 8) Lakeville-Sonoma 115 kV line #1

The substations that delineate the Lakeville sub-area are:

1) Lakeville 230 kV 2) Ignacio 230 kV 3) Tulucay 230 kV 4) Lakeville 115 kV

Total busload within the defined area: 1457 MW with 56 MW of losses resulting

in total load + losses of 1513 MW.

Total units and qualifying capacity available in this area: Gen Bus Gen Name ID Qualifying Capacity (MW) 31433 POTTRVLY 3 2.5 31433 POTTRVLY 1 5.5 31433 POTTRVLY 4 2.5 31430 SMUDGEO1 1 38 31406 GEYSR5-6 1 36 31406 GEYSR5-6 2 36 31408 GEYSER78 1 31 31408 GEYSER78 2 31 31412 GEYSER11 1 60 31414 GEYSER12 1 41 31416 GEYSER13 1 70 31418 GEYSER14 1 63 31420 GEYSER16 1 75 31422 GEYSER17 1 51 31424 GEYSER18 1 40 31426 GEYSER20 1 40 38106 NCPA1GY1 1 59 38108 NCPA1GY2 1 59 38110 NCPA2GY1 1 60 38112 NCPA2GY2 1 60 31400 SANTA FE 2 39.1 31404 WEST FOR 2 14 31400 SANTA FE 1 39.1 31402 BEAR CAN 1 8.3 31402 BEAR CAN 2 8 31404 WEST FOR 1 14 32700 MONTICLO 1 3.3 32700 MONTICLO 2 3.4 32700 MONTICLO 3 0 31435 GEO.ENGY 1 8.6 31435 GEO.ENGY 2 8.9 31436 INDIAN V 1 3.7 31446 SONMA LF 1 7.7

Total 1018.6 Critical Contingency Analysis Summary Eagle Rock-Fulton Sub-area

The most critical overlapping contingency is the outage of the Fulton-Ignacio

230 kV line #1 and the Fulton-Lakeville 230 kV line #1. The sub-area area limitation

is thermal overloading of Sonoma-Pueblo 115 kV line #1. This limiting contingency

establishes a Local Capacity Requirement of 371 MW (includes 80 MW of QF

generation) as the minimum capacity necessary for reliable load serving capability

within this sub-area. Out of this amount, 182 MW is required among the units

connected directly to the Eagle Rock substation (includes 21 MW of QF generation).

The most critical single contingency in the sub-area is the outage of Cortina 230/115

kV transformer #1. This limiting contingency establishes a Local Capacity

Requirement of 245 MW (includes 80 MW of QF generation) as the minimum

capacity necessary for reliable load serving capability within this sub-area.

Effectiveness factors:

The following table has units within the Eagle Rock-Fulton pocket as well as

units outside the pocket that are at least 5% effective to the above-mentioned

constraint.

Single contingency

Gen Bus Gen Name Gen ID MW Eff Fctr Location 31404 WEST FOR 2 56 Fulton 31404 WEST FOR 1 56 Fulton 31414 GEYSER12 1 56 Fulton 31418 GEYSER14 1 56 Fulton 31420 GEYSER16 1 56 Fulton 31422 GEYSER17 1 56 Fulton 38110 NCPA2GY1 1 56 Fulton 38112 NCPA2GY2 1 56 Fulton 31406 GEYSR5-6 1 53 Eagle Rock 31406 GEYSR5-6 2 53 Eagle Rock 31408 GEYSER78 1 53 Eagle Rock 31408 GEYSER78 2 53 Eagle Rock 31412 GEYSER11 1 53 Eagle Rock

Overlapping Contingency

Gen Bus Gen Name Gen ID MW Eff Fctr Location 31404 WEST FOR 2 27 Fulton 31404 WEST FOR 1 27 Fulton 31414 GEYSER12 1 27 Fulton 31418 GEYSER14 1 27 Fulton 31420 GEYSER16 1 27 Fulton 31422 GEYSER17 1 27 Fulton

38110 NCPA2GY1 1 27 Fulton 38112 NCPA2GY2 1 27 Fulton 31406 GEYSR5-6 1 17 Eagle Rock 31406 GEYSR5-6 2 17 Eagle Rock 31408 GEYSER78 1 17 Eagle Rock 31408 GEYSER78 2 17 Eagle Rock 31412 GEYSER11 1 17 Eagle Rock

Lakeville Sub-area Operations solutions to mitigate the most limiting constraint in the Lakeville

pocket, as previously described in the LCR report, has been validated in this area in

order to reduce the total LCR requirement both under single and overlapping

contingency conditions. After implementing the operating solutions, the most critical

contingency for Lakeville sub-area would be the outage of Vaca Dixon-Tulucay 230

kV line #1 and Geysers 13 unit. The sub-area limitation is thermal overloading of the

Lakeville-Vaca-Dixon 230 kV #1. This limiting contingency establishes a Local

Capacity Requirement of 582 MW for single contingency in this sub-area (includes

158 MW of QF generation). The LCR requirement for Eagle Rock/Fulton sub-area

can be counted toward fulfilling the requirement of Lakeville sub-area.

Effectiveness factors:

The following table has units at least 5% effective to the above-mentioned

constraint.

Gen Bus Gen Name Gen ID MW Eff Fctr Location

31400 SANTA FE 2 25 Lakeville 31430 SMUDGEO1 1 25 Lakeville 31400 SANTA FE 1 25 Lakeville 31416 GEYSER13 1 25 Lakeville 31424 GEYSER18 1 25 Lakeville 31426 GEYSER20 1 25 Lakeville 38106 NCPA1GY1 1 25 Lakeville 38108 NCPA1GY2 1 25 Lakeville 31404 WEST FOR 2 22 Fulton 31404 WEST FOR 1 22 Fulton 31414 GEYSER12 1 22 Fulton 31418 GEYSER14 1 22 Fulton 31420 GEYSER16 1 22 Fulton 31422 GEYSER17 1 22 Fulton 38110 NCPA2GY1 1 22 Fulton

38112 NCPA2GY2 1 22 Eagle Rock 31406 GEYSR5-6 1 8 Eagle Rock 31406 GEYSR5-6 2 8 Eagle Rock 31408 GEYSER78 1 8 Eagle Rock 31408 GEYSER78 2 8 Eagle Rock 31412 GEYSER11 1 8 Eagle Rock

North Coast/North Bay Overall Requirements:

QF/Seflgen (MW)

Muni (MW)

Market (MW)

Max. Qualifying Capacity (MW)

Available generation 158 0 861 1019 Existing Generation

Capacity Needed (MW) Deficiency

(MW) Total MW

Requirement Category B (Single)12 582 0 582 Category C (Multiple)13 582 0 582

3. Sierra Area Area Definition The transmission tie lines into the Sierra Area are:

1) Table Mountain-Rio Oso 230 kV line 2) Table Mountain-Palermo 230 kV line 3) Table Mt-Pease 60 kV line 4) Caribou-Palermo 115 kV line 5) Drum-Summit 115 kV line #1 6) Drum-Summit 115 kV line #2 7) Spaulding-Summit 60 kV line 8) Brighton-Bellota 230 kV line 9) Rio Oso-Lockeford 230 kV line 10) Gold Hill-Eight Mile Road 230 kV line 11) Gold Hill-Lodi Stig 230 kV line 12) Gold Hill-Lake 230 kV line

The substations that delineate the Sierra Area are:

1) Table Mountain 60 kV 2) Table Mountain 230 kV

12 A single contingency means that the system will be able the survive the loss of a single element, however the operators will not have any means (other then load drop) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by MORC. 13 Multiple contingencies means that the system will be able the survive the loss of a single element, and the operators will have enough generation (other operating procedures) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by MORC.

3) Big Bend 115 kV 4) Drum 115 kV 5) Tamarack 60 kV 6) Brighton 230 kV 7) Rio Oso 230 kV 8) Gold Hill 230 kV

Total busload within the defined area: 1742.4 MW with 98.5 MW of losses resulting in total load + losses of 1840.9 MW. Total units and qualifying capacity available in this area:

Gen No Gen Name ID Qualifying Capacity 31888 OROVLLE 1 8.9 31890 PO POWER 2 9.8 31890 PO POWER 1 9.8 31834 KELLYRDG 1 10 31814 FORBSTWN 1 39.7 31794 WOODLEAF 1 55 31862 DEADWOOD 1 2 31832 SLY.CR. 1 13.2 32470 CMP.FARW 1 6.5 32450 COLGATE1 1 165.8 32452 COLGATE2 1 165.7 32466 NARROWS1 1 3.6 32468 NARROWS2 1 10.1 32451 FREC 1 47 32490 GRNLEAF1 2 10 32490 GRNLEAF1 1 51.1 32156 WOODLAND 1 28.6 32494 YUBA CTY 1 50.2 32496 YCEC 1 47 32492 GRNLEAF2 1 50.3 32166 UC DAVIS 1 3.5 31812 CRESTA 1 35 31812 CRESTA 2 35 31788 ROCK CK2 1 56 31820 BCKS CRK 1 33 31820 BCKS CRK 2 25 31790 POE 1 1 60 31792 POE 2 1 60 31786 ROCK CK1 1 56 31784 BELDEN 1 115 32162 RIV.DLTA 1 3.1 32502 DTCHFLT2 1 26 32476 ROLLINSF 1 11.7 32474 DEER CRK 1 5.7 32454 DRUM 5 1 49.5 32504 DRUM 1-2 1 13

32504 DRUM 1-2 2 13 32506 DRUM 3-4 1 14 32506 DRUM 3-4 2 14 32484 OXBOW F 1 6 32472 SPAULDG 1 4.4 32472 SPAULDG 2 7 32472 SPAULDG 3 5.8 32498 SPILINCF 1 13.7 32464 DTCHFLT1 1 22 32500 ULTR RCK 1 28.5 32480 BOWMAN 1 3.8 32488 HAYPRES+ 1 12.3 32488 HAYPRES+ 2 8.7 32462 CHI.PARK 1 38 32478 HALSEY F 1 11 32512 WISE 1 10.8 32460 NEWCSTLE 1 5.9 32510 CHILIBAR 1 7 32513 ELDRADO1 1 10 32514 ELDRADO2 1 10 32458 RALSTON 1 86 32456 MIDLFORK 1 63.4 32456 MIDLFORK 2 63.4 32486 HELLHOLE 1 0.5 32508 FRNCH MD 1 17

1848 Critical Contingency Analysis Summary South of Table Mountain Sub-area The most critical contingency is the loss of the Table Mountain-Rio Oso 230 kV line with one of the Colgate Units out of service. The area limitation is thermal overloading of the Table Mt-Palermo 230 kV line. This limiting contingency establishes a Local Capacity Requirement of 1630 MW (includes 1072 MW of QF and Muni generation) as the minimum capacity necessary for reliable load serving capability within this pocket. Effectiveness factors:

Gen No Gen Name ID Qualifying CapacityDFAX

(%) 31888 OROVLLE 1 8.9 72 31890 PO POWER 2 9.8 72 31890 PO POWER 1 9.8 72 31834 KELLYRDG 1 10 72 31814 FORBSTWN 1 39.7 62 31794 WOODLEAF 1 55 62 31862 DEADWOOD 1 2 61 31832 SLY.CR. 1 13.2 61

32470 CMP.FARW 1 6.5 54 32450 COLGATE1 1 165.8 52 32452 COLGATE2 1 165.7 52 32466 NARROWS1 1 3.6 52 32468 NARROWS2 1 10.1 52 32451 FREC 1 47 42 32490 GRNLEAF1 2 10 41 32490 GRNLEAF1 1 51.1 41 32156 WOODLAND 1 28.6 28 32494 YUBA CTY 1 50.2 27 32496 YCEC 1 47 27 32492 GRNLEAF2 1 50.3 27 32166 UC DAVIS 1 3.5 26 31812 CRESTA 1 35 24 31812 CRESTA 2 35 24 31788 ROCK CK2 1 56 24 31820 BCKS CRK 1 33 24 31820 BCKS CRK 2 25 24 31790 POE 1 1 60 24 31792 POE 2 1 60 24 31786 ROCK CK1 1 56 24 31784 BELDEN 1 115 23 32162 RIV.DLTA 1 3.1 21 32502 DTCHFLT2 1 26 21 32476 ROLLINSF 1 11.7 20 32474 DEER CRK 1 5.7 20 32454 DRUM 5 1 49.5 20 32504 DRUM 1-2 1 13 20 32504 DRUM 1-2 2 13 20 32506 DRUM 3-4 1 14 20 32506 DRUM 3-4 2 14 20 32484 OXBOW F 1 6 20 32472 SPAULDG 1 4.4 20 32472 SPAULDG 2 7 20 32472 SPAULDG 3 5.8 20 32498 SPILINCF 1 13.7 20 32464 DTCHFLT1 1 22 20 32500 ULTR RCK 1 28.5 19 32480 BOWMAN 1 3.8 19 32488 HAYPRES+ 1 12.3 19 32488 HAYPRES+ 2 8.7 19 32462 CHI.PARK 1 38 19 32478 HALSEY F 1 11 19 32512 WISE 1 10.8 19 32460 NEWCSTLE 1 5.9 18 32510 CHILIBAR 1 7 17 32513 ELDRADO1 1 10 17 32514 ELDRADO2 1 10 17 32458 RALSTON 1 86 17 32456 MIDLFORK 1 63.4 17

32456 MIDLFORK 2 63.4 17 32486 HELLHOLE 1 0.5 16 32508 FRNCH MD 1 17 16

1848 Colgate Sub-area The most critical contingency is the loss of the Colgate-Smartville #1 60 kV line with one of the Narrows #2 (or Camp far West) units out of service. The area limitation is thermal overloading of the Colgate-Smartville #2 60 kV line. This limiting contingency establishes a Local Capacity Requirement of 17 MW (includes 17 MW of QF and Muni generation) as the minimum capacity necessary for reliable load serving capability within this pocket. Effectiveness factors:

All units within this area (Narrows #2 and Camp Far West) are needed therefore no effectiveness factor is required. Pease Sub-area The most critical contingency is the loss of the Palermo-East Nicolaus 115 kV line with one of the Greenleaf #2 (or Yuba City) units out of service. The area limitation is thermal overloading of the Palermo-Pease 115 kV line. This limiting contingency establishes a Local Capacity Requirement of 111 MW (includes 100 MW of QF and Muni generation) as the minimum capacity necessary for reliable load serving capability within this pocket. Effectiveness factors:

All units within this area (Greenleaf #2, Yuba City and Yuba City EC) are needed therefore no effectiveness factor is required. Bogue Sub-area The most critical contingency is the loss of the Pease-Rio Oso 115 kV line with one of the Greenleaf #1 (or Feather River EC) units out of service. The area limitation is thermal overloading of the Palermo-Bogue 115 kV line. This limiting contingency establishes a Local Capacity Requirement of 101 MW (includes 61 MW of QF and Muni generation) as the minimum capacity necessary for reliable load serving capability within this pocket. Effectiveness factors:

All units within this area (Greenleaf #1 units 1&2 and Feather River EC) are needed therefore no effectiveness factor is required. South of Palermo Sub-area The most critical contingency is the loss of the Double Circuit Tower Line Table Mountain-Rio Oso and Colgate-Rio Oso 230 kV lines. The area limitation is thermal

overloading of the Palermo-East Nicolaus 115 kV line. This limiting contingency establishes a Local Capacity Requirement of 1037 MW (includes 142 MW of QF and Muni generation as well as 250 MW of Deficiency) as the minimum capacity necessary for reliable load serving capability within this pocket. The single most critical contingency is the loss of the Palermo-Pease 115 kV line with Belden unit out of service. The area limitation is thermal overloading of the Palermo-East Nicolaus 115 kV line. This limiting contingency establishes a Local Capacity Requirement of 980 MW (includes 142 MW of QF and Muni generation as well as 193 MW of Deficiency) as the minimum capacity necessary for reliable load serving capability within this pocket. The Sierra case provided had a normal overload on the Palermo-East Nicolaus 115 kV line that can be resolved by changing the normal tap point for the East Marysville substation from the Palermo-East Nicolaus 115 kV line to the Pease-Rio Oso 115 kV line and by having at least 680 MW of generation on-line (from maximum 787 MW generation available – includes 142 MW of QF and Muni). Effectiveness factors:

All units (listed below) within this area are needed therefore no effectiveness factor is required.

Gen No Gen Name ID Qualifying Capacity32476 ROLLINSF 1 11.7 32474 DEER CRK 1 5.7 32504 DRUM 1-2 1 13 32504 DRUM 1-2 2 13 32506 DRUM 3-4 1 14 32506 DRUM 3-4 2 14 32454 DRUM 5 1 49.5 32484 OXBOW F 1 6 32472 SPAULDG 1 4.4 32472 SPAULDG 2 7 32472 SPAULDG 3 5.8 32480 BOWMAN 1 3.8 32488 HAYPRES+ 1 12.3 32488 HAYPRES+ 2 8.7 32156 WOODLAND 1 28.6 32166 UC DAVIS 1 3.5 32502 DTCHFLT2 1 26 32464 DTCHFLT1 1 22 32162 RIV.DLTA 1 3.1 32462 CHI.PARK 1 38 31812 CRESTA 1 35 31812 CRESTA 2 35 31788 ROCK CK2 1 56 31820 BCKS CRK 1 33

31820 BCKS CRK 2 25 31790 POE 1 1 60 31792 POE 2 1 60 31786 ROCK CK1 1 56 31784 BELDEN 1 115 32478 HALSEY F 1 11 32512 WISE 1 10.8

786.9

Placerville Sub-area The most critical contingency is the loss of the Gold Hill-Clarksville 115 kV line followed by loss of the Gold Hill-Missouri Flat #2 115 kV line. The area limitation is thermal overloading of the Gold Hill-Missouri Flat #1 115 kV line. This limiting contingency establishes a Local Capacity Requirement of 83 MW (includes 0 MW of QF and Muni generation as well as 56 MW of Deficiency) as the minimum capacity necessary for reliable load serving capability within this pocket. Effectiveness factors:

All units within this area (El Dorado units 1&2 and Chili Bar) are needed therefore no effectiveness factor is required. Placer Sub-area The most critical contingency is the loss of the Drum-Higgins 115 kV line followed by loss of the Gold Hill-Placer #2 115 kV line. The area limitation is thermal overloading of the Gold Hill-Placer #1 115 kV line. This limiting contingency establishes a Local Capacity Requirement of 123 MW (includes 0 MW of QF and Muni generation as well as 95 MW of Deficiency) as the minimum capacity necessary for reliable load serving capability within this pocket. The single most critical contingency is the loss of the Drum-Higgins 115 kV line with the Wise #1 unit out of service. The area limitation is thermal overloading of the Gold Hill-Placer #1 115 kV line. This limiting contingency establishes a Local Capacity Requirement of 52 MW (includes 0 MW of QF and Muni generation as well as 24 MW of Deficiency) as the minimum capacity necessary for reliable load serving capability within this pocket. Effectiveness factors:

All units within this area (Wise units 1&2, Newcastle and Halsey) are needed therefore no effectiveness factor is required. Drum-Rio Oso Sub-area The most critical contingency is the loss of the Rio Oso #2 230/115 transformer followed by loss of the Rio Oso-Brighton 230 kV line. The area limitation is thermal overloading of the Rio Oso #1 230/115 kV transformer. This limiting contingency

establishes a Local Capacity Requirement of 701 MW (includes 413 MW of QF and Muni generation as well as 45 MW of Deficiency) as the minimum capacity necessary for reliable load serving capability within this pocket. The single most critical contingency is the loss of the Rio Oso #2 230/115 transformer. The area limitation is thermal overloading of the Rio Oso #1 230/115 kV transformer. This limiting contingency establishes a Local Capacity Requirement of 352 MW (includes 413 MW of QF and Muni generation) as the minimum capacity necessary for reliable load serving capability within this pocket. Effectiveness factors:

All units within this area are needed for the most limiting contingency therefore no effectiveness factor is required. Effectiveness factors are given for the single most limiting contingency. Gen No Gen Name ID Qualifying Capacity DFAX (%)32156 WOODLAND 1 28.6 31 32490 GRNLEAF1 2 10 29 32490 GRNLEAF1 1 51.1 29 32451 FREC 1 47 28 32166 UC DAVIS 1 3.5 25 32502 DTCHFLT2 1 26 20 32476 ROLLINSF 1 11.7 19 32474 DEER CRK 1 5.7 18 32454 DRUM 5 1 49.5 18 32504 DRUM 1-2 1 13 18 32504 DRUM 1-2 2 13 18 32506 DRUM 3-4 1 14 18 32506 DRUM 3-4 2 14 18 32484 OXBOW F 1 6 18 32472 SPAULDG 1 4.4 18 32472 SPAULDG 2 7 18 32472 SPAULDG 3 5.8 18 32480 BOWMAN 1 3.8 18 32488 HAYPRES+ 1 12.3 18 32488 HAYPRES+ 2 8.7 18 32496 YCEC 1 47 16 32494 YUBA CTY 1 50.2 16 32492 GRNLEAF2 1 50.3 16 32464 DTCHFLT1 1 22 15 32162 RIV.DLTA 1 3.1 15 32462 CHI.PARK 1 38 12 31862 DEADWOOD 1 2 7 31814 FORBSTWN 1 39.7 7 31832 SLY.CR. 1 13.2 7 31794 WOODLEAF 1 55 7

655.6

South of Rio Oso Sub-area The most critical contingency is the loss of the Rio Oso-Gold Hill 230 line followed by loss of the Gold Hill-Ralston 230 kV line or vice versa. The area limitation is thermal overloading of the Rio Oso-Atlantic 230 kV line. This limiting contingency establishes a Local Capacity Requirement of 230 MW (includes 80 MW of QF and Muni generation as well as 95 MW of Deficiency) as the minimum capacity necessary for reliable load serving capability within this pocket. The single most critical contingency is the loss of the Rio Oso-Gold Hill 230 line with the Ralston unit out of service. The area limitation is thermal overloading of the Rio Oso-Atlantic 230 kV line. This limiting contingency establishes a Local Capacity Requirement of 132 MW (includes 80 MW of QF and Muni generation) as the minimum capacity necessary for reliable load serving capability within this pocket. Effectiveness factors:

All units within this area are needed for the most limiting contingency therefore no effectiveness factor is required. Effectiveness factors are given for the second most limiting contingency.

Gen No Gen Name ID Qualifying Capacity DFAX (%)32498 SPILINCF 1 13.7 50 32500 ULTR RCK 1 28.5 49 32514 ELDRADO2 1 10 33 32513 ELDRADO1 1 10 33 32510 CHILIBAR 1 7 33 32460 NEWCSTLE 1 5.9 27 32478 HALSEY F 1 11 25 32512 WISE 1 10.8 25 32462 CHI.PARK 1 38 9

134.9 Sierra Overall Requirements:

QF (MW)

Muni (MW)

Market (MW)

Max. Qualifying Capacity (MW)

Available generation 267 805 776 1848 Existing Generation

Capacity Needed (MW) Deficiency

(MW) Total MW

Requirement Category B (Single)14 1833 205 2038 Category C (Multiple)15 1833 328 2161

14 A single contingency means that the system will be able the survive the loss of a single element, however the operators will not have any means (other then load drop) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by MORC. 15 Multiple contingencies means that the system will be able the survive the loss of a single element, and the operators will have enough generation (other operating procedures) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by MORC.

4. Stockton Area

Area Definition The transmission facilities that establish the boundary of the Tesla-Bellota Sub-area are:

1) Bellota 230/115 kV Transformer #1 2) Bellota 2

30/115 kV Transformer #2 3) Tesla-Tracy 115 kV Line 4) Tesla-Salado 115 kV Line 5) Tesla-Salado-Manteca 115 kV line 6) Tesla-Shulte 115 kV Line 7) Tesla-Kasson-Manteca 115 kV Line

The substations that delineate the Tesla-Bellota Sub-area are:

1) Tesla 115 kV 2) Bellota 115 kV

The transmission facilities that establish the boundary of the Lockeford Sub-area are:

1) Lockeford-Industrial 60 kV line 2) Lockeford-Lodi #1 60 kV line 3) Lockeford-Lodi #2 60 kV line 4) Lockeford-Lodi #3 60 kV line

The substations that delineate the Lockeford Sub-area is:

1) Lockeford 60 kV The transmission facilities that establish the boundary of the Stagg Sub-area are:

1) Tesla – Stagg 230 kV Line 2) Tesla – Eight Mile Road 230 kV Line 3) Gold Hill – Eight Mile Road 230 kV Line 4) Gold Hill - Lodi Stigg 230 kV Line

The substations that delineate the Stagg Sub-area is:

1) Tesla 230 kV 2) Gold Hill 230 kV

Total busload within the defined area: 1240 MW with 27 MW of losses resulting in total load + losses of 1267 MW. Total units and qualifying capacity available in this area:

Name ID Qualifying Capacity GWFTRCY2 1 79.2 GWFTRCY1 1 79.8 FBERBORD 1 5.7 BELLTA T 1 0 CH.STN. 1 22.3

STNSLSRP 1 19.9 CPC STCN 1 62.9

CAMANCHE 1 3.7 CAMANCHE 2 3.7 CAMANCHE 3 3.7 DONNELLS 1 67.5 BEARDSLY 1 11 TULLOCH 1 9 TULLOCH 2 9 SANDBAR 1 16.8 SPRNG GP 1 6.7 STANISLS 1 91 LODI25CT 1 25.6 GEN.MILL 1 3.4

Stig CC 1 50 570.9

Critical Contingency Analysis Summary

Stockton overall The requirement for this area is driven by the sum of requirements for the Tesla-Bellota, Lockeford, and Stagg Sub-areas.

Tesla-Bellota Sub-area The critical contingency for the Tesla-Bellota pocket is the loss of Tesla-Tracy 115 kV and Tesla-Schulte 115 kV #1. The area limitation is thermal overloading of the Manteca-Ingram Creek section of Tesla-Salado-Manteca 115 kV line above its emergency rating. This limiting contingency establishes a Local Capacity Requirement of 458 MW (includes 235 MW of QF and Muni generation) as the minimum capacity necessary for reliable load serving capability within this area. The single most critical contingency for the Tesla-Bellota pocket is the loss of Tesla-Kasson-Manteca 115 kV line and the loss of the Stanislaus unit #1. This single contingency establishes a Local Capacity Requirement of 432 MW (includes 235 MW of QF and Muni generation).

Effectiveness factors: All units within this area are needed for the most limiting contingency therefore no effectiveness factor is required.

Lockeford Sub-area The critical contingency for the Lockeford area is the loss of Lockeford-Industrial 60 kV circuit and Lockeford-Lodi #2 60 kV circuit. The area limitation is thermal overloading of the Lockeford-Colony section of the Lockeford-Lodi #1 60 kV circuit. This limiting contingency establishes a Local Capacity Requirement of 81 MW (including 28 MW of QF and Muni as well as a deficiency of 53 MW) as the minimum capacity necessary for reliable load serving capability within this area. Effectiveness factors: All units within this area (Lodi CT and General Mill) are needed therefore no effectiveness factor is required.

Stagg Sub-area The outage of the Tesla-Stagg 230 kV line and Tesla-Eight Mile 230 kV line causes low voltages at Stagg, Eight Mile Road and Lodi Stig 230 kV busses. Post-contingency steady-state voltages at these three busses are less than 0.90 pu. Lodi Stig generating unit is needed to support voltage at these three 230 kV busses. This limiting contingency establishes a Local Capacity Requirement of 50 MW as the minimum capacity necessary for reliable load serving capability within this area. Effectiveness factors: The only unit within this area (Lodi Stig) is needed therefore no effectiveness factor is required. Stockton Overall Requirements:

QF (MW)

Muni (MW)

Market (MW)

Max. Qualifying Capacity (MW)

Available generation 114 200 257 571 Existing Generation

Capacity Needed (MW) Deficiency

(MW) Total MW

Requirement Category B (Single)16 432 0 432 Category C (Multiple)17 536 53 589

16 A single contingency means that the system will be able the survive the loss of a single element, however the operators will not have any means (other then load drop) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by MORC.

5. Greater Bay Area

Area Definition The transmission tie lines into the Greater Bay Area are:

1) Lakeville-Sobrante 230 kV 2) Ignacio-Sobrante 230 kV 3) Parkway-Moraga 230 kV 4) Bahia-Moraga 230 kV 5) Lambie SW Sta-Vaca Dixon 230 kV 6) Peabody-Contra Costa P.P. 230 kV 7) Kelso-Brentwood 230 kV 8) Tesla-Delta Switching Yard 230 kV 9) Tesla-Pittsburg #1 230 kV 10) Tesla-Pittsburg #2 230 kV 11) Tesla-Newark #1 230 kV 12) Tesla-Newark #2 230 kV 13) Tesla-Tracy #1 230 kV 14) Tesla-Tracy #2 230 kV 15) Tesla-Ravenswood 230 kV 16) Tesla-Metcalf 500 kV 17) Moss Landing-Metcalf 500 kV 18) Moss Landing-Metcalf #1 230 kV 19) Moss Landing-Metcalf #2 230 kV 20) Green Valley-Morgan Hill #1 115 kV 21) Green Valley-Morgan Hill #2 115 kV 22) Oakdale TID-Newark #1 115 kV 23) Oakdale TID-Newark #2 115 kV

The substations that delineate the Greater Bay Area are:

1) Lakeville 230 kV 2) Ignacio 230 kV 3) Moraga 230 kV 4) Lambie SW Sta 230 kV 5) Kelso 230 kV 6) Peabody 230 kV 7) Pittsburg 230 kV 8) Tesla 230 kV 9) Metcalf 500 kV 10) Moss Landing 500 kV

17 Multiple contingencies means that the system will be able the survive the loss of a single element, and the operators will have enough generation (other operating procedures) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by MORC.

11) Morgan Hill 115 kV 12) Newark 115 kV

Total busload within the defined area: 9402 MW with 231 MW of losses resulting in total load + losses of 9633 MW. Total units and qualifying capacity available in this area:

No Name ID Qualifying Capacity38118 ALMDACT1 1 25.6 38119 ALMDACT2 1 25.6 33114 C.COS 4 1 0 33115 C.COS 5 1 0 33116 C.COS 6 1 345 33117 C.COS 7 1 345 33463 CARDINAL 2 10 33463 CARDINAL 1 17.8 35863 CATALYST 1 0 36856 CCA100 1 32 33136 CCCSD 1 4.4 32921 ChevGen1 1 54 32922 ChevGen2 1 54 36854 Cogen 2 3 36854 Cogen 1 3 32900 CRCKTCOG 1 243 32175 CREEDGT1 3 47 33145 CROWN.Z. 2 5.4 33145 CROWN.Z. 1 40 33108 DEC CTG1 1 173 33109 DEC CTG2 1 173 33110 DEC CTG3 1 173 33107 DEC STG1 1 294 33161 DOWCHEM1 1 16.8 33162 DOWCHEM2 1 22 33163 DOWCHEM3 1 22 36863 DVR A GT 1 47 36865 DVR A ST 1 50 36864 DVR B GT 1 50 35318 FLOWDPTR 1 5.7 33151 FOSTER W 3 35 33151 FOSTER W 1 45.4 33151 FOSTER W 2 45.4 36858 Gia100 1 21 36895 Gia200 1 21 35850 GLRY COG 2 40 35850 GLRY COG 1 80 32174 GOOSEHGT 2 46

35851 GROYPKR1 1 45 35852 GROYPKR2 1 45 35853 GROYPKR3 1 45 33131 GWF #1 1 20 33132 GWF #2 1 20 33133 GWF #3 1 20 33134 GWF #4 1 20 33135 GWF #5 1 20 32172 HIGHWNDS 1 13 32740 HILLSIDE 1 26.2 35637 IBM-CTLE 1 50 32173 LAMBGT1 1 47 35854 LECEFGT1 1 48 35855 LECEFGT2 1 48 35856 LECEFGT3 1 48 35857 LECEFGT4 1 48 35310 LFC FIN+ 1 8.9 33112 LMECCT1 1 165 33111 LMECCT2 1 165 33113 LMECST1 1 230 35881 MEC CTG1 1 184 35882 MEC CTG2 1 186 35883 MEC STG1 1 227 33121 MRAGA 1T 1 0 33122 MRAGA 2T 1 0 33123 MRAGA 3T 1 0 32901 OAKLND 1 1 55 32902 OAKLND 2 1 55 32903 OAKLND 3 1 55 35860 OLS-AGNE 1 28.5 33252 POTRERO3 1 210 33253 POTRERO4 1 52 33254 POTRERO5 1 52 33255 POTRERO6 1 52 33105 PTSB 5 1 320 33106 PTSB 6 1 325 30000 PTSB 7 1 710 33178 RVEC_GEN 1 48 35312 SEAWESTF 1 3.3 33141 SHELL 1 1 20 33142 SHELL 2 1 40 33143 SHELL 3 1 40 32176 SHILOH 1 0 35861 SJ-SCL W 1 5 33462 SMATO1SC 1 0 33460 SMATO2SC 1 0 33461 SMATO3SC 1 0 32169 SOLANOWP 1 10

33468 SRI INTL 1 3.3 33139 STAUFER 1 2.3 32920 UNION CH 1 20.4 32910 UNOCAL 1 10 32910 UNOCAL 2 10 32910 UNOCAL 3 10 33466 UNTED CO 1 27.2 35320 USW FRIC 1 3.4 35320 USW FRIC 2 0 32168 USWINDPW 2 3.4 33838 USWP_#3 1 20.5 33170 WINDMSTR 1 3.6 35316 ZOND SYS 1 6.2

6545 Critical Contingency Analysis Summary

San Francisco Sub-area Per the CAISO Revised Action Plan for SF, all Potrero units (360 MW) will continued to be required until completion of the plan as it is presently described. The most critical contingency is an overlapping outage of two 115 kV cables between Martin and Hunters Point Substations. The area limitation is thermal overloading of the Martin-Bayshore-Potrero 115 kV #1 and #2 cables. This limiting contingency requires all of the existing Potrero Power plant generation (Potrero units 3-6) 360 MW be on-line. Effectiveness factors:

All units within this sub-area are needed therefore no effectiveness factor is required.

Oakland Sub-area The most critical contingency is an outage of the D-L 115 kV cable (with one of the Oakland CT’s off-line) The sub-area area limitation is thermal overloading of the C-X 115 kV cableThis limiting contingency establishes a Local Capacity Requirement of 100 MW (includes 50 MW of Muni generation) as the minimum capacity necessary for reliable load serving capability within this sub-area. Effectiveness factors:

All units within this sub-area have the same effectiveness factor. Units outside of this sub-area are not effective. Llagas Sub-area

The most critical contingency is an outage between Metcalf D and Morgan Hill 115 kV (with one of the Gilroy Peaker off-line). The area limitation is thermal overloading of the Metcalf-Llagas 115 kV line. As documented within a CAISO Operating Procedure, this limitation is dependent on power flowing in the direction from Metcalf to Llagas/Morgan Hill. This limiting contingency establishes a Local Capacity Requirement of 100 MW as the minimum capacity necessary for reliable load serving capability within this area. Effectiveness factors: All units within this area have the same effectiveness factor. Units outside of this area are not effective.

San Jose Sub-area The most critical contingency is the category C outage of Evergreen 1 – Markham – San Jose B 115 kV line and the Metcalf D – IBM HR – El Patio 115 kV line. The area limitation is thermal overloading of the Baily J3 – El Patio 115 kV line.This contingency prevents the Metcalf E 115 bus from feeding the San Jose B 115 kV load. Power must flow through the remaining Metcalf D – El Patio 115 kV circuit and then to the load at San Jose B 115 kV bus. This limiting contingency establishes a Local Capacity Requirement of 457 MW (including 265 MW of QF and Muni generation) as the minimum capacity necessary for reliable load serving capability for this outage. Effectiveness factors: All units within this area have the same effectiveness factor. Units outside of this area are not effective.

Name ID Qualifying Capacity

Cogen 2 3 Cogen 1 3 DVR A ST 1 51 DVR B GT 1 48.4 DVR A GT 1 48.4 Gia100 1 21 LECEFGT4 1 48 LECEFGT3 1 48 LECEFGT2 1 48 LECEFGT1 1 48 IBM-CTLE 1 50 OLS-AGNE 1 29 SJ-SCL W 1 5.5 CCA100 1 35.9 CATALYST 1 2

Gia200 1 21 510.2

Pittsburg Sub-area The most critical contingency is an outage of the Pittsburg-Tesla #1 or #2 230 kV line (with Delta Energy Center off-line). The sub-area area limitation is thermal overloading of the parallel Pittsburg-Tesla 230 kV line. This limiting contingency establishes a Local Capacity Requirement of 2208 MW (including 678 MW of QF generation) as the minimum capacity necessary for reliable load serving capability within this sub-area. Effectiveness factors:

The following table has units within the Pittsburg pocket as well as units outside the pocket that are at least 5% effective to the above-mentioned constraint.

Gen Bus Gen Name Gen ID MW Eff Fctr33840 FLOWD3-6 1 86 33840 FLOWD3-6 2 86 33840 FLOWD3-6 3 86 33840 FLOWD3-6 4 86 33171 TRSVQ+NW 2 26 33171 TRSVQ+NW 1 26 33105 PTSB 5 1 26 33106 PTSB 6 1 26 30000 PTSB 7 1 26 33110 DEC CTG3 1 25 33109 DEC CTG2 1 25 33108 DEC CTG1 1 25 33107 DEC STG1 1 25 33113 LMECST1 1 24 33112 LMECCT1 1 24 33111 LMECCT2 1 24 33132 GWF #2 1 24 33161 DOWCHEM1 1 24 33162 DOWCHEM2 1 24 33163 DOWCHEM3 1 24 33151 FOSTER W 1 23 33151 FOSTER W 2 23 33151 FOSTER W 3 23 33141 SHELL 1 1 21 33143 SHELL 3 1 21 33142 SHELL 2 1 21 32900 CRCKTCOG 1 19 32910 UNOCAL 1 19 32910 UNOCAL 2 19 32910 UNOCAL 3 19

32920 UNION CH 1 19 32922 ChevGen2 1 18 32921 ChevGen1 1 18 32740 HILLSIDE 1 18 33135 GWF #5 1 18 38119 ALMDACT2 1 16 32903 OAKLND 3 1 16 32902 OAKLND 2 1 16 32901 OAKLND 1 1 16 38118 ALMDACT1 1 16 31404 WEST FOR 2 14 31402 BEAR CAN 1 14 31402 BEAR CAN 2 14 31404 WEST FOR 1 14 31414 GEYSER12 1 14 31416 GEYSER13 1 14 31418 GEYSER14 1 14 31420 GEYSER16 1 14 31422 GEYSER17 1 14 31424 GEYSER18 1 14 31426 GEYSER20 1 14 38110 NCPA2GY1 1 14 38112 NCPA2GY2 1 14 31400 SANTA FE 2 13 31430 SMUDGEO1 1 13 31400 SANTA FE 1 13 38106 NCPA1GY1 1 13 38108 NCPA1GY2 1 13 31406 GEYSR5-6 1 10 31406 GEYSR5-6 2 10 31408 GEYSER78 1 10 31408 GEYSER78 2 10 31412 GEYSER11 1 10 31435 GEO.ENGY 1 10 31435 GEO.ENGY 2 10 30464 EXXON_BH 1 9 33252 POTRERO3 1 7 33271 HNTRS P1 1 7 33270 HNTRS P4 1 7 33253 POTRERO4 1 7 33254 POTRERO5 1 7 33255 POTRERO6 1 7 33466 UNTED CO 1 7 35312 SEAWESTF 1 7 35316 ZOND SYS 1 7 35320 USW FRIC 1 7 32176 SHILOH 1 5 36865 DVRPPSTA 1 5

36864 DVRPPCT2 1 5 36863 DVRPPCT1 1 5 32185 WOLFSKIL 1 5 33178 RVEC_GEN 1 5 32175 CREEDGT1 3 5 32174 GOOSEHGT 2 5 32173 LAMBGT1 1 5 32150 DG_VADIX 1 5 32172 HIGHWNDS 1 5 33134 GWF #4 1 5 33116 C.COS 6 1 5 33117 C.COS 7 1 5 32154 WADHAM 1 5 33133 GWF #3 1 5 33145 CROWN.Z. 1 5 33145 CROWN.Z. 2 5 33131 GWF #1 1 5 36856 CSC_CCA 1 5 33463 CARDINAL 1 5 33463 CARDINAL 2 5 32168 USWINDPW 1 5 32168 USWINDPW 2 5 33838 USWP_#3 1 5

Bay Area overall PG&E has proposed and the CAISO has validated and implemented a new operating procedure. As such the LCR need for the most critical contingency: the loss of the Vaca Dixon 500/230 kV transformer followed by loss of the Contra Costa unit 7 or vice versa, has been reduced. As a result the most critical contingency is the loss of the Vaca Dixon 500/230 kV transformer. The area limitation is thermal overloading of the Tesla-Delta Switching Yard 230 kV line. This limiting contingency establishes a Local Capacity Requirement of 4771 MW (includes 1314 MW of Wind, QF and Muni generation) as the minimum capacity necessary for reliable load serving capability within this area. Effectiveness factors:

For most helpful procurement information please read procedure T-133Z effectiveness factors – Bay Area at:

http://www.caiso.com/docs/2004/11/01/2004110116234011719.pdf Bay Area Overall Requirements:

Wind (MW)

QF/Selfgen (MW)

Muni (MW)

Market (MW)

Max. Qualifying Capacity (MW)

Available generation 78 988 248 5231 6545

http://www.caiso.com/docs/2004/11/01/2004110116234011719.pdf

Existing Generation

Capacity Needed (MW) Deficiency

(MW) Total MW

Requirement Category B (Single)18 4771 0 4771 Category C (Multiple)19 4771 0 4771

6. Greater Fresno Area Area Definition The transmission facilities coming into the Greater Fresno area are:

1) Gates-Henrietta Tap 1 230 kV 2) Gates-Henrietta Tap 2 230 kV 3) Gates #1 230/115 kV Transformer Bank 4) Los Banos #3 230/70 Transformer Bank 5) Los Banos #4 230/70 Transformer Bank 6) Panoche-Gates #1 230 kV 7) Panoche-Gates #2 230 kV 8) Panoche-Coburn 230 kV 9) Panoche-Moss Landing 230 kV 10) Panoche-Los Banos #1 230 kV 11) Panoche-Los Banos #2 230 kV 12) Panoche-Dos Amigos 230 kV 13) Warnerville-Wilson 230 kV 14) Wilson-Melones 230 kV 15) Corcoran – Alpaugh - Smyrna 115 kV 16) Coalinga #1-San Miguel 70 kV

The substations that delineate the Greater Fresno area are:

1) Los Banos 230 kV 2) Gates 230 kV 3) Panoche 230 kV 4) Wilson 230 kV 5) Alpaugh 115 kV 6) Coalinga 70 kV

Total busload within the defined area: 3051 MW with 103 MW of losses resulting in total load + losses of 3154 MW. Total units and qualifying capacity available in this area: 18 A single contingency means that the system will be able the survive the loss of a single element, however the operators will not have any means (other then load drop) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by MORC. 19 Multiple contingencies means that the system will be able the survive the loss of a single element, and the operators will have enough generation (other operating procedures) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by MORC.

No Name ID Qualifying Capacity

34636 FRIANTDM 4 3.5 34636 FRIANTDM 3 8.7 34636 FRIANTDM 2 16.3 34608 AGRICO 2 7 34608 AGRICO 3 18.9 34608 AGRICO 4 26 34672 KRCDPCT2 1 56 34671 KRCDPCT1 1 56 34485 FRESNOWW 1 9 34142 WHD_PAN2 1 49 34553 WHD_GAT2 1 49 34179 MADERA_G 1 28.7 34433 GWF_HEP2 1 39.1 34431 GWF_HEP1 1 40 34541 GWF_GT2 1 45.1 34539 GWF_GT1 1 45.3 34186 DG_PAN1 1 49 34301 CHOWCOGN 1 52.5 34618 MCCALL1T 1 0 34621 MCCALL3T 1 0 34630 HERNDN1T 1 0 34632 HERNDN2T 1 0 38720 PINE FLT 1 75 38720 PINE FLT 2 75 38720 PINE FLT 3 75 34306 EXCHQUER 1 70.8 34658 WISHON 1 5 34658 WISHON 2 5 34658 WISHON 3 5 34658 WISHON 4 5 34344 KERCKHOF 1 8.5 34344 KERCKHOF 2 13 34344 KERCKHOF 3 12.8 34308 KERCKHOF 1 155 34600 HELMS 1 1 404 34602 HELMS 2 1 404 34604 HELMS 3 1 404 34610 HAAS 1 69.9 34610 HAAS 2 69.9 34624 BALCH 1 1 34 34612 BLCH 2-2 1 52.5 34614 BLCH 2-3 1 52.5 34616 KINGSRIV 1 52 34316 ONEILPMP 1 11 34320 MCSWAIN 1 3.9

34322 MERCEDFL 1 1.9 34658 WISHON SJ 0.4 34631 SJ2GEN 1 3.2 34633 SJ3GEN 1 4.2 34332 JRWCOGEN 1 8.5 34334 BIO PWR 1 26.1 34640 ULTR.PWR 1 26.4 34642 KINGSBUR 1 35.3 34646 SANGERCO 1 42.9 34648 DINUBA E 1 13.5 34650 GWF-PWR. 1 25 34652 CHV.COAL 1 4.1 34652 CHV.COAL 2 14.8 34654 COLNGAGN 1 42.3 34342 INT.TURB 1 1.1

2912 Critical Contingency Analysis Summary

Wilson Sub-area The most critical contingency for the Wilson sub-area is the loss of the Wilson - Melones 230 kV line with one of the Helm units out of service, which would thermally overload the Wilson - Warnerville 230 kV line. This limiting contingency establishes a Local Capacity Requirement of 1449 MW (which includes 75 MW of muni generation and 215 MW of QF generation) as the generation capacity necessary for reliable load serving capability within this sub-area. Effectiveness factors:

The following table has units within Fresno that are at least 5% effective to the above-mentioned constraint. All units in Fresno not listed or units outside of this area have smaller effectiveness factors.

Gen Bus Gen Name Gen ID MW Eff Fctr 34332 JRWCOGEN 1 40 34322 MERCEDFL 1 33 34320 MCSWAIN 1 32 34306 EXCHQUER 1 31 34600 HELMS 1 1 31 34602 HELMS 2 1 31 34604 HELMS 3 1 31 34301 CHOWCOGN 1 29 34636 FRIANTDM 1 25 34485 FRESNOWW 1 24 34658 WISHON 1 24 34658 WISHON 2 24

34658 WISHON 3 24 34658 WISHON 4 24 34631 SJ2GEN 1 24 34633 SJ3GEN 1 23 34344 KERCKHOF 1 22 34344 KERCKHOF 2 22 34344 KERCKHOF 3 22 34308 KERCKHOF 1 22 34179 MADERA_G 1 20 34648 DINUBA E 1 19 34672 KRCDPCT2 1 18 34671 KRCDPCT1 1 18 34624 BALCH 1 1 18 34640 ULTR.PWR 1 18 34646 SANGERCO 1 18 38720 PINE FLT 1 17 38720 PINE FLT 2 17 38720 PINE FLT 3 17 34616 KINGSRIV 1 17 34642 KINGSBUR 1 17 34433 GWF_HEP2 1 14 34431 GWF_HEP1 1 14 34610 HAAS 1 14 34610 HAAS 2 14 34612 BLCH 2-2 1 14 34614 BLCH 2-3 1 14 34539 GWF_GT1 1 13 34334 BIO PWR 1 13 34541 GWF_GT2 1 12 34650 GWF-PWR. 1 12 34142 WHD_PAN2 1 11 34186 DG_PAN1 1 11 34608 AGRICO 2 10 34608 AGRICO 3 10 34608 AGRICO 4 10 34553 WHD_GAT2 1 8 34652 CHV.COAL 1 8 34652 CHV.COAL 2 8 34654 COLNGAGN 1 8 34342 INT.TURB 1 6 34316 ONEILPMP 1 6

Herndon Sub-area Generation curtailment has been done as part of the system readjustment that occurs between the first contingency and the second contingency. As such the LCR need for the most critical contingency in the Herndon sub-area: the loss of the

Herndon 230/115 kV bank 1 with Kerckhoff #2 unit out of service, which would thermally overload the parallel Herndon 230/115 kV bank 2, has been reduced. As a result the most critical contingency for the Herndon sub-area is the loss of the Herndon 230/115 kV bank 1, which would thermally overload the parallel Herndon 230/115 kV bank 2. This limiting contingency establishes a Local Capacity Requirement of 719 MW (which includes 149 MW of QF generation) as the minimum generation capacity necessary for reliable load serving capability within this sub-area. Effectiveness factors:

The following table has units within Fresno area that have at least 5% relative effectiveness to the above-mentioned constraint. All units in Fresno not listed or units outside of this area have smaller effectiveness factors.

Gen Bus Gen Name Gen ID MW Eff Fctr

34308 KERCKHOF 1 36 34344 KERCKHOF 1 35 34344 KERCKHOF 2 35 34344 KERCKHOF 3 35 34624 BALCH 1 1 33 34646 SANGERCO 1 32 34672 KRCDPCT2 1 31 34671 KRCDPCT1 1 31 34616 KINGSRIV 1 31 34640 ULTR.PWR 1 31 34648 DINUBA E 1 29 34642 KINGSBUR 1 26 38720 PINE FLT 1 22 38720 PINE FLT 2 22 38720 PINE FLT 3 22 34612 BLCH 2-2 1 22 34610 HAAS 1 21 34610 HAAS 2 21 34614 BLCH 2-3 1 21 34433 GWF_HEP2 1 14 34431 GWF_HEP1 1 14 34301 CHOWCOGN 1 9 34608 AGRICO 2 7 34608 AGRICO 3 7 34608 AGRICO 4 7 34334 BIO PWR 1 3 34652 CHV.COAL 1 3 34652 CHV.COAL 2 3 34553 WHD_GAT2 1 2 34179 MADERA_G 1 2

34654 COLNGAGN 1 2 34332 JRWCOGEN 1 -5 34485 FRESNOWW 1 -13 34600 HELMS 1 1 -15 34602 HELMS 2 1 -15 34604 HELMS 3 1 -15

McCall Sub-area The most critical contingency for the McCall sub-area is the loss of Mc Call #3 230/115 kV transformer bank with GWF Hanford Peaker #1 unit out of service, which would thermally overload the McCall #2 230/115 kV transformer bank. This limiting contingency establishes a Local Capacity Requirement of 1,462 MW (which includes 192 MW of QF generation and 108 MW of Muni generation) as the generation capacity necessary for reliable load serving capability within this sub-area. The most critical single contingency for the McCall sub-area is the loss of Mc Call #3 230/115 kV transformer bank, which would thermally overload the McCall #2 230/115 kV transformer bank. This limiting contingency establishes a Local Capacity Requirement of 1,405 MW (which includes 192 MW of QF generation and 108 MW of Muni generation). Effectiveness factors:

See line 6 under attached link below. Henrietta Sub-area The most critical contingency for the Henrietta sub-area is the loss of new Henrietta 230/70 kV transformer bank with Henrietta-GWF Henrietta 70 kV line out of service, which would thermally overload the old Henrietta 230/70 kV transformer bank. This combined limit establishes a Local Capacity Requirement of 117 MW (which includes 25 MW of QF generation and 2 MW of deficiency) as the minimum generation capacity necessary for reliable load serving capability within this sub-area. The most critical single contingency for the Henrietta sub-area is the loss of new Henrietta 230/70 kV transformer bank, which would thermally overload the old Henrietta 230/70 kV transformer bank. This combined limit establishes a Local Capacity Requirement of 34 MW (which includes 25 MW of QF generation). Effectiveness factors:

All units within this sub-area have the same effectiveness factor. Units outside of this sub-area are not effective. Merced Sub-area

The most critical contingencies for the Merced sub-area is the double line outage of the Wilson – Atwater 115 kV #1 and #2 lines, which would thermally overload the Wilson – Merced 115 kV #1 and #2 lines. This limiting contingency establishes a Local Capacity Requirement of 151 MW (which includes 75 MW of muni generation, 9 MW of QF generation and 66 MW of area deficiency) as the minimum generation capacity necessary for reliable load serving capability within this sub-area. Effectiveness factors: All units within this sub-area are needed therefore no effectiveness factor is required.

No Name ID Qualifying Capacity34306 EXCHQUER 1 70.8 34320 MCSWAIN 1 3.9 34322 MERCEDFL 1 1.9 34332 JRWCOGEN 1 8.5 Because of the overlapping LCR MWs requirements among the sub-areas, the total aggregate LCR requirement for the Greater Fresno Area is 2219 MW (includes 108 MW of muni generation, 222 MW of QF generation and 68 MW of deficiency). Additional helpful effectiveness factors for Fresno area:

Please read procedure T-129Z effectiveness factors - Fresno Area at: http://www.caiso.com/docs/2005/07/13/2005071314483315210.pdf

Fresno Area Overall Requirements:

QF/Selfgen (MW)

Muni (MW)

Market (MW)

Max. Qualifying Capacity (MW)

Available generation 275 300 2337 2912 Existing Generation

Capacity Needed (MW) Deficiency

(MW) Total MW

Requirement Category B (Single)20 2115 0 2115 Category C (Multiple)21 2151 68 2219

7. Kern Area Area Definition

20 A single contingency means that the system will be able the survive the loss of a single element, however the operators will not have any means (other then load drop) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by MORC. 21 Multiple contingencies means that the system will be able the survive the loss of a single element, and the operators will have enough generation (other operating procedures) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by MORC.

http://www.caiso.com/docs/2005/07/13/2005071314483315210.pdf

The transmission facilities coming into the Kern PP sub-area are:

1) Wheeler Ridge-Lamont 115 kV line 2) Kern PP 230/115 kV Bank # 3 & 3A 3) Kern PP 230/115 kV Bank # 4 4) Kern PP 230/115 kV Bank # 5 5) Midway 230/115 Bank # 1 6) Midway 230/115 Bank # 2 & 2a 7) Temblor – San Luis Obispo 115 kV line

These sub-stations form the boundary surrounding the Kern PP sub-area:

1) Midway 115 kV 2) Kern PP 115 kV 3) Wheeler Ridge 115 kV 4) Temblor 115 kV

The transmission facilities coming into the Weedpatch sub-area are:

1) Wheeler Ridge 115/60 kV Bank 2) Wheeler Ridge 230/60 kV Bank

These sub-stations form the boundary surrounding the Weedpatch sub-area:

1) Wheeler Ridge 60 kV Total busload within the defined area: 1191 MW with 18 MW of losses resulting in total load + losses of 1209 MW. Total units and qualifying capacity available in this Kern PP sub-area:

No Name ID Qualifying Capacity35056 TX-LOSTH 1 9 35034 MIDSUN + 1 20 35037 UNIVRSTY 1 39.9 35038 CHLKCLF+ 1 49.9 35006 KERN 1 1 0 35008 KERN 2 1 0 35024 DEXEL + 1 32.1 35026 KERNFRNT 1 52.7 35029 BADGERCK 1 48.9 35027 HISIERRA 1 52.7 35023 DOUBLE C 1 51.9 35028 OILDALE 1 40.1 35032 CHV-CYMR 1 22.7 34783 TEXCO_NM 1 12 34783 TEXCO_NM 2 9

35036 MT POSO 1 56.1 35035 ULTR PWR 1 36.4 35040 KERNRDGE 1 66 35040 KERNRDGE 2 14.2 35044 TX MIDST 1 39.8 35046 SEKR 1 34.2 35048 FRITOLAY 1 7.1 35050 SLR-TANN 1 17.4 35052 CHEV.USA 1 14.4 35058 PSE-LVOK 1 49 35060 PSEMCKIT 1 50.8 35062 DISCOVRY 1 44 35064 NAVY 35R 1 31.9 35064 NAVY 35R 2 32.5 35066 PSE-BEAR 1 51.3

Total 986 Total units and qualifying capacity available in this Kern PP sub-area:

No Name ID Qualifying Capacity35018 KERNCNYN 1 11.2 35020 RIOBRAVO 1 12.1

Total 23.3 Critical Contingency Analysis Summary Kern PP Sub-area The most critical contingency for the Kern PP sub-area is the outage of the Kern PP #5 230/115 kV transformer bank and the Kern PP – Kern Front 115 kV line, which would thermally overload the parallel Kern PP 230/115 kV Bank 3 and Bank 3a. This limiting contingency establishes a Local Capacity Requirement of 749 MW (which includes 749 MW of QF generation) as the minimum generation capacity necessary for reliable load serving capability within this sub-area. The most critical single contingency for the Kern PP sub-area is the loss of Kern PP #5 230/115 kV transformer bank, which would thermally overload the parallel Kern PP 230/115 kV Bank 3 and Bank 3a. This limiting contingency establishes a Local Capacity Requirement of 554 MW (which includes 554 MW of QF generation) as the minimum generation capacity necessary for reliable load serving capability within this sub-area. Effectiveness factors:

All units within this sub-area are under long-term contracts. No additional procurement needs to be done; therefore no effectiveness factor is required.

Wheedpatch Sub-area

The most critical contingency is the loss of the Wheeler Ridge – San Bernard 70 kV line and the Wheeler Ridge – Tejon 70 kV line, which would thermally overload the Wheeler Ridge – Weedparch 70 kV line and cause low voltage problem at the local 70 kV transmission system. This limiting contingency establishes a Local Capacity Requirement of 36 MW (which includes 8 MW of QF generation and 17 MW of area deficiency) as the minimum generation capacity necessary for reliable load serving capability within this sub-area. Effectiveness factors:

All units within this sub-area are needed therefore no effectiveness factor is required. Kern Area Overall Requirements:

QF/Selfgen (MW)

Market (MW)

Max. Qualifying Capacity (MW)

Available generation 978 31 1009 Existing Generation

Capacity Needed (MW) Deficiency

(MW) Total MW

Requirement Category B (Single)22 554 0 554 Category C (Multiple)23 769 17 786

8. LA Basin Area Area Definition The transmission tie lines into the LA Basin Area are:

1) San Onofre - San Luis Rey #1, #2, & #3 230 kV Lines 2) San Onofre - Talega #1 & #2 230 kV Lines 3) Lugo - Mira Loma #1, #2 & #3 500 kV Lines 4) Sylmar LA - Sylmar S #1, #2 & #3 230/230 kV Transformers 5) Sylmar S - Pardee #1 & #2 230 kV Lines 6) Vincent - Mesa Cal #1 230 kV Line 7) Antelope - Mesa Cal #1 230 kV Line 8) Vincent - Rio Hondo #1 & #2 230 kV Lines 9) Eagle Rock - Pardee #1 230 kV Line 10) Devers - Valley #1 500 kV Line

22 A single contingency means that the system will be able the survive the loss of a single element, however the operators will not have any means (other then load drop) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by MORC. 23 Multiple contingencies means that the system will be able the survive the loss of a single element, and the operators will have enough generation (other operating procedures) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by MORC.

11) Devers #1 & #2 500/230 kV Transformers 12) Devers - Coachelv # 1 230 kV Line 13) Mirage - Ramon # 1 230 kV Line 14) Julian Hinds-Eagle Mountain 230 kV

These sub-stations form the boundary surrounding the LA Basin area:

1) Devers 500 kV 2) Mirage 230 kV 3) Vincent 230 kV 4) San Onofre 230 kV 5) Sylmar 230 kV 6) Lugo 500 kV

Total busload within the defined area is 19055 MW with 173 MW of losses and 97 MW of pumps resulting in total load + losses of 19325 MW. Total units and qualifying capacity available in the Eastern sub-area: BUS-NO NAME1 ID Qualifying Capacity Subarea 24052 MTNVIST3 3 319 Eastern LA Basin 24053 MTNVIST4 4 320 Eastern LA Basin 28190 WINTECX2 1 44 Eastern LA Basin 28191 WINTECX1 1 42 Eastern LA Basin 28180 WINTEC8 1 42 Eastern LA Basin 24921 MNTV-CT1 1 143.5 Eastern LA Basin 24922 MNTV-CT2 1 143.5 Eastern LA Basin

24923 MNTV-ST1 1 249 Eastern LA Basin 24924 MNTV-CT3 1 143.5 Eastern LA Basin 24925 MNTV-CT4 1 143.5 Eastern LA Basin 24926 MNTV-ST2 1 249 Eastern LA Basin 25632 TERAWND 1 1 Eastern LA Basin 25633 CAPWIND 1 1 Eastern LA Basin 25634 BUCKWND 1 1 Eastern LA Basin 25635 ALTWIND 1 2.9 Eastern LA Basin 25636 RENWIND 1 1 Eastern LA Basin 25637 TRANWND 1 2.9 Eastern LA Basin 25639 SEAWIND 1 3 Eastern LA Basin 25640 PANAERO 1 1.9 Eastern LA Basin 25645 VENWIND 1 1.9 Eastern LA Basin 25646 SANWIND 1 1 Eastern LA Basin 24826 INDIGO 1 17 Eastern LA Basin 24815 GARNET 1 1 Eastern LA Basin 28020 WINTEC6 1 1.9 Eastern LA Basin 28060 SEAWEST 1 1.9 Eastern LA Basin 28060 SEAWEST 2 1.9 Eastern LA Basin

28280 CABAZON 1 1.9 Eastern LA Basin 24030 DELGEN 1 33.1 Eastern LA Basin 24071 INLAND 1 19.7 Eastern LA Basin 24140 SIMPSON 1 34 Eastern LA Basin 24902 VSTA 1 0 Eastern LA Basin 24229 VALLEY-S 1 0 Eastern LA Basin 25991 VALYSVC2 1 0 Eastern LA Basin 25990 VALYSVC1 1 0 Eastern LA Basin 24902 VSTA 2 1.3 Eastern LA Basin 24214 SANBRDNO 2 0.5 Eastern LA Basin 24214 SANBRDNO 1 0.1 Eastern LA Basin 24055 ETIWANDA 2 34.7 Eastern LA Basin 24055 ETIWANDA 1 0.6 Eastern LA Basin 25422 ETI MWDG 1 23.7 Eastern LA Basin 28061 WHITEWTR 1 52.8 Eastern LA Basin 28260 ALTAMSA4 1 32 Eastern LA Basin 24160 VALLEYSC 1 4.2 Eastern LA Basin 24111 PADUA 2 5.8 Eastern LA Basin 24111 PADUA 1 0.5 Eastern LA Basin 24024 CHINO 1 9.9 Eastern LA Basin 25648 DVLCYN1G 1 50.7 Eastern LA Basin 25649 DVLCYN2G 2 50.7 Eastern LA Basin 25603 DVLCYN3G 1 67.7 Eastern LA Basin 25604 DVLCYN4G 2 67.7 Eastern LA Basin

Total 2371.9 Total units and qualifying capacity available in the Western sub-area: BUS-NO NAME1 ID PMAX Subarea 24001 ALAMT1 G 1 174.6 Western LA Basin 24002 ALAMT2 G 2 175 Western LA Basin 24003 ALAMT3 G 3 332.2 Western LA Basin 24004 ALAMT4 G 4 335.7 Western LA Basin 24005 ALAMT5 G 5 485 Western LA Basin 24161 ALAMT6 G 6 495 Western LA Basin 24162 ALAMT7 G 7 0 Western LA Basin 25203 ANAHEIMG 1 46.6 Western LA Basin 24018 BRIGEN 1 35 Western LA Basin 24020 CARBOGEN 1 29 Western LA Basin 24047 ELSEG3 G 3 335 Western LA Basin 24048 ELSEG4 G 4 335 Western LA Basin 24066 HUNT1 G 1 225.8 Western LA Basin 24067 HUNT2 G 2 225.8 Western LA Basin 24167 HUNT3 G 3 225 Western LA Basin 24168 HUNT4 G 4 227.4 Western LA Basin 24120 PULPGEN 1 40 Western LA Basin 24121 REDON5 G 5 178.9 Western LA Basin

24122 REDON6 G 6 175 Western LA Basin 24123 REDON7 G 7 493.2 Western LA Basin 24124 REDON8 G 8 486.9 Western LA Basin 24133 SANTIAGO 1 17 Western LA Basin 24062 HARBOR G 0 88.6 Western LA Basin 25510 HARBORG4 LP 5.7 Western LA Basin 24062 HARBOR G HP 5.7 Western LA Basin 24011 ARCO 1G 1 64.7 Western LA Basin 24012 ARCO 2G 2 64.7 Western LA Basin 24013 ARCO 3G 3 64.7 Western LA Basin 24014 ARCO 4G 4 64.7 Western LA Basin 24163 ARCO 5G 5 31.2 Western LA Basin 24164 ARCO 6G 6 31.2 Western LA Basin 24022 CHEVGEN1 1 0.8 Western LA Basin 24023 CHEVGEN2 2 0.8 Western LA Basin 24026 CIMGEN 1 26.1 Western LA Basin 24063 HILLGEN 1 37.3 Western LA Basin 24070 ICEGEN 1 46.2 Western LA Basin 24139 SERRFGEN 1 25.2 Western LA Basin 24203 CENTER S 1 25.2 Western LA Basin 24075 LAGUBELL 1 11.2 Western LA Basin 24073 LA FRESA 1 5.7 Western LA Basin 24094 MOBGEN 1 45 Western LA Basin 24064 HINSON 1 25.2 Western LA Basin 24027 COLDGEN 1 28 Western LA Basin 24060 GROWGEN 1 28 Western LA Basin 24169 HUNT5 G 5 0 Western LA Basin 24213 RIOHONDO 1 0.9 Western LA Basin 24209 MESA CAL 1 0.6 Western LA Basin 24208 LCIENEGA 1 2.3 Western LA Basin 24083 LITEHIPE 1 0.3 Western LA Basin 24028 DELAMO 1 0 Western LA Basin 24157 WALNUT 1 7.9 Western LA Basin 28005 PASADNA1 1 22.5 Western LA Basin 28006 PASADNA2 1 22.5 Western LA Basin 28007 BRODWYSC 1 65 Western LA Basin 24211 OLINDA 1 2.3 Western LA Basin 24197 ELLIS 1 7.1 Western LA Basin 24129 S.ONOFR2 2 1115 Western LA Basin 24130 S.ONOFR3 3 1105 Western LA Basin

Total 8150.4 Critical Contingency Analysis Summary LA Basin overall: The combined Local Area Requirement is 8843 MW of which 3510 MW includes the San Onofre Nuclear Power Plant, QF and Muni generation. The Western and

Eastern sub-area contingencies require 884324 MW as the minimum amount of generating capacity necessary for reliable load serving capability within these sub-areas. 2042 MW of this capacity is needed in the Eastern sub-area, and the rest (6802 MW) is needed in the Western sub-area. The two critical contingencies in the Eastern Sub-area are: (1) Loss of Devers – Valley 500 kV line, followed by the loss of two Lugo – Mira Loma 500 kV lines #2 and #3, and (2) Loss of one San Onofre Nuclear Generator, followed by the loss of two Lugo – Mira Loma 500 kV lines #2 and #3. The sub-area area limitation is low area post-transient voltage associated with voltage collapse. Effectiveness factors:

The area limitation is low area post-transient voltage associated with voltage collapse. The units in the Eastern area or geographically close to it are the most effective units. The critical contingency for the in the Western Sub-area is the loss of Lugo-Victorville 500 kV, followed by loss of Sylmar-Gould 230 kV line. The sub-area area limitation is thermal overloading of the Eagle Rock-Mesa 230 kV line.

The following table has units that have at least 5% effectiveness to the above-mentioned constraint within the LA Basin area.

Gen Bus Gen Name Gen ID MW Eff Fctr24209 MESA CAL 1 19 24011 ARCO 1G 1 18 24012 ARCO 2G 2 18 24013 ARCO 3G 3 18 24014 ARCO 4G 4 18 24164 ARCO 6G 6 18 24047 ELSEG3 G 3 18 24048 ELSEG4 G 4 18 24121 REDON5 G 5 18 24122 REDON6 G 6 18 24123 REDON7 G 7 18 24124 REDON8 G 8 18 24163 ARCO 5G 5 17 24020 CARBOGEN 1 17 24064 HINSON 1 17 24070 ICEGEN 1 17 24094 MOBGEN 1 17

24 This value is based on a potential higher South of Lugo (SOL) limit with RAS operation which needs to be determined by SCE. Based on the current 5600 MW SOL limit, the total LA Basin generation requirement would increase by an additional 900 MW for a total of 9743 MW to respect loss of a SONG unit.

24139 SERRFGEN 1 17 24062 HARBOR G 0 17 25510 HARBORG4 LP 17 24062 HARBOR G HP 17 28005 PASADNA1 1 17 28006 PASADNA2 1 17 28007 BRODWYSC 1 17 24208 LCIENEGA 1 17 24083 LITEHIPE 1 17 24075 LAGUBELL 1 17 24073 LA FRESA 1 17 24028 DELAMO 1 17 24001 ALAMT1 G 1 16 24002 ALAMT2 G 2 16 24003 ALAMT3 G 3 16 24004 ALAMT4 G 4 16 24005 ALAMT5 G 5 16 24161 ALAMT6 G 6 16 24018 BRIGEN 1 16 24027 COLDGEN 1 16 24060 GROWGEN 1 16 24063 HILLGEN 1 16 24120 PULPGEN 1 16 24213 RIOHONDO 1 16 24203 CENTER S 1 16 24157 WALNUT 1 16 24167 HUNT3 G 3 15 24066 HUNT1 G 1 14 24067 HUNT2 G 2 14 24168 HUNT4 G 4 14 24133 SANTIAGO 1 14 24197 ELLIS 1 14 25203 ANAHEIMG 1 13 24026 CIMGEN 1 13 24030 DELGEN 1 13 24071 INLAND 1 13 24140 SIMPSON 1 13 25422 ETI MWDG 1 13 24902 VSTA 2 13 24111 PADUA 2 13 24111 PADUA 1 13 24024 CHINO 1 13 25648 DVLCYN1G 1 12 25649 DVLCYN2G 2 12 25603 DVLCYN3G 3 12 25604 DVLCYN4G 4 12 24052 MTNVIST3 3 12

24053 MTNVIST4 4 12 24129 S.ONOFR2 2 12 24130 S.ONOFR3 3 12 24921 MNTV-CT1 1 12 24922 MNTV-CT2 1 12 24923 MNTV-ST1 1 12 24924 MNTV-CT3 1 12 24925 MNTV-CT4 1 12 24926 MNTV-ST2 1 12 24214 SANBRDNO 2 12 24214 SANBRDNO 1 12 24055 ETIWANDA 2 12 24055 ETIWANDA 1 12 25632 TERAWND 1 11 25633 CAPWIND 1 11 25634 BUCKWND 1 11 25635 ALTWIND 1 11 25636 RENWIND 1 11 25637 TRANWND 1 11 25639 SEAWIND 1 11 25640 PANAERO 1 11 25645 VENWIND 1 11 25646 SANWIND 1 11 24826 INDIGO 1 11 28190 WINTECX2 1 11 28191 WINTECX1 1 11 28180 WINTEC8 1 11 24815 GARNET 1 11 24828 WINTEC9 1 11 28020 WINTEC6 1 11 28060 SEAWEST 1 11 28060 SEAWEST 2 11 28061 WHITEWTR 1 11 28260 ALTAMSA4 1 11 28280 CABAZON 1 11

LA Basin Overall Requirements:

QF/Wind (MW)

Muni (MW)

Nuclear (MW)

Market (MW)

Max. Qualifying Capacity (MW)

Available generation 829 461 2220 7012 10522 Existing Generation Deficiency Total MW

Capacity Needed (MW) (MW) Requirement Category B (Single)25 8843 0 8843 Category C (Multiple)26 8843 0 8843

9. San Diego Area Area Definition The transmission tie lines forming a boundary around San Diego include:

1) Imperial Valley – Miguel 500 kV Line 2) Miguel – Tijuana 230 kV Line 3) San Onofre - San Luis Rey #1 230 kV Line 4) San Onofre - San Luis Rey #2 230 kV Line 5) San Onofre - San Luis Rey #3 230 kV Line 6) San Onofre – Talega #1 230 kV Line 7) San Onofre – Talega #2 230 kV Line

These sub-stations form the boundary surrounding the San Diego area:

1) Miguel 230 kV 2) San Luis Rey 230 kV 3) Talega 230 kV

Total busload within the defined area: 4637 MW with 105 MW of losses resulting in total load + losses of 4742 MW. Total units and qualifying capacity available in this area:

No Name ID Qualifying Capacity22088 BOULEVRD 1 0.5 22092 CABRILLO 1 3.6 22172 DIVISION 1 46.9 22212 ELCAJNGT 1 15 22233 ENCINA 1 1 103.5 22234 ENCINA 2 1 104 22236 ENCINA 3 1 110 22240 ENCINA 4 1 300 22244 ENCINA 5 1 330 22248 ENCINAGT 1 15 22332 GOALLINE 1 50

25 A single contingency means that the system will be able the survive the loss of a single element, however the operators will not have any means (other then load drop) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by MORC. 26 Multiple contingencies means that the system will be able the survive the loss of a single element, and the operators will have enough generation (other operating procedures) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by MORC.

22376 KEARN3CD 1 15.3 22384 KYOCERA 1 0.1 22480 MIRAMAR 1 2.7 22488 MIRAMRGT 1 18 22532 MURRAY 1 0.5 22576 NOISLMTR 1 35.3 22660 POINTLMA 1 21.8 22680 R.SNTAFE 1 0.5 22688 RINCON 1 0.5 22704 SAMPSON 1 13.6 22724 SANMRCOS 1 1.1 22776 SOUTHBGT 1 13 22780 SOUTHBY1 1 145 22784 SOUTHBY2 1 149 22788 SOUTHBY3 1 174 22792 SOUTHBY4 1 221 22820 SWEETWTR 1 0.5 22120 CARLTNHS 1 1.1 22149 CALPK_BD 1 42 22153 CALPK_ES 1 45.5 22150 CALPK_EC 1 42 22604 OTAY 1 3 22373 KEARN2AB 1 14.8 22373 KEARN2AB 2 14.8 22374 KEARN2CD 1 14.8 22374 KEARN2CD 2 14.8 22375 KEARN3AB 1 15.3 22375 KEARN3AB 2 15.3 22376 KEARN3CD 2 15.3 22377 KEARNGT1 1 16 22488 MIRAMRGT 2 18 22074 LRKSPBD1 1 46 22075 LRKSPBD2 1 46 22257 RAMCO_ES 1 40 22617 RAMCO_OY 1 42 22834 TALEGA SC 0 22486 RAMCO_MR 1 45 22262 PEN_CT1 1 177 22263 PEN_CT2 1 177 22265 PEN_ST 1 187 22904 CAMPOGEN 1 10 22904 CAMPOGEN 2 0

2932 Critical Contingency Analysis Summary

San Diego overall: The most limiting contingency in the San Diego area is described by the outage of 500 kV Southwest Power Link (SWPL) between Imperial Valley and Miguel Substations over-lapping with an outage of the Palomar Combined-Cycle Power plant (541 MW) while staying within the South of San Onofre (WECC Path 44) non-simultaneous import capability rating of 2,500 MW. Therefore the 2,781 MW (includes 181 MW of QF generation and 10 MW of wind) of capacity required within this area is predicated on having sufficient generation in the San Diego Area to reduce Path 44 to its non-simultaneous rating of 2500 MW within 30 minutes. Effectiveness factors:

All units within this area have the same effectiveness factor. Units outside of this area are not effective. San Diego Overall Requirements:

QF (MW)

Wind (MW)

Market (MW)

Max. Qualifying Capacity (MW)

Available generation 181 10 2741 2932 Existing Generation

Capacity Needed (MW) Deficiency

(MW) Total MW

Requirement Category B (Single)27 2781 0 2781 Category C (Multiple)27F

28 2781 0 2781

C. Zonal Capacity Requirements The ISO performed an assessment of the Zonal Capacity needs for year 2007 based on the methodology presented in chapter III section B. These results refer to the ISO control area only, they do not include requirements for other control areas like: LADWP, IID, SMUD-WAPA, TID or MID.

Zone Load

Forecast (MW)

Generator Outages

(MW)

Single Worst Contingency

(MW)

(-)Import Capability

(MW)

Total Requirement

(MW) SP26 28,778 1,500 2,000 10,100 22,178 NP26=NP15+ZP26 21,518 2,500 1,160 5,348 19,830 NP15 Path 15 is not a binding constraint at this time

27 A single contingency means that the system will be able the survive the loss of a single element, however the operators will not have any means (other then load drop) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by MORC. 28 Multiple contingencies means that the system will be able the survive the loss of a single element, and the operators will have enough generation (other operating procedures) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by MORC.

Units need in order to comply with the Local Area Capacity Requirements fully count toward the Zonal Requirements. San Diego and LA Basin are situated in SP26, Kern in ZP26 and the rest in NP15. V. Future Annual Technical Analyses For future local area capacity requirements studies, the CPUC should

consider the use of the Loss of Load Probability (LOLP) methodology, used by many

eastern regions. LOLP is a study methodology that can be used to establish the

level of capacity required in each local area by performing a probabilistic analysis to

achieve a specified probability for loss of load. Underlying this approach is an

expected level of service reliability. In the established Eastern markets, a one-event

in ten years LOLP methodology is used to determine LSE capacity obligations. The

LOLP approach provides a potentially more uniform reliability result than the

proposed deterministic approach. In the future, if the LOLP approach is determined

to be a more desirable approach, then the LOLP analysis will be incorporated into

the criteria if and when a criteria and methodology for applying it has been

developed. Any LOLP criteria and methodology will need to be reviewed by

stakeholders and approved by the CPUC. Until such time, the LOLP approach will

not be used to establish LSE capacity requirements, and the deterministic approach

defined above will be used.

California Independent System Operator

2007 LCR Study

Prepared By

Planning & Infrastructure DevelopmentApril 26, 2006

P&ID / April 26, 2006

California Independent System Operator

Agenda• Introduction• Elements of the CAISO’s Analysis

– Input Assumptions– Methodology

• Summary of Findings• Detailed Summary of Findings• Discussion• Next Steps

California Independent System Operator

Elements of the CASIO’s AnalysisInput Assumptions

MethodologySummary of Findings

P&ID / April 26, 2006

California Independent System Operator

P&ID / April 26, 2006

California Independent System Operator

Input AssumptionsThe input assumptions used were developed from a “meet and confer” session held on February 17, 2006 as well as the errata filing submitted on March 10, 2006. Administrative Law Judge adopted the proposed assumptions. This information was used in the 2007 LCR Study.

Input Assumptions:

• Transmission System Configuration

• Generation Modeled The existing generation resources has been modeled and also includes all projects that will be on-line and commercial on or before June 1, 2007

• Load Forecast Uses a 1-in-10 year summer peak load forecast

P&ID / April 26, 2006

California Independent System Operator

Methodology

Methodology:

• Maximize Import Capability Import capability into the load pocket has been maximized, thus minimizing the generation required in the load pocket to meet applicable reliability requirements.

• QF/Nuclear/State/Federal Units

Regulatory Must-take and similarly situated units like QF/Nuclear/State/Federal resources have been modeled on-line at historical output values for purposes of the 2007 LCR Study.

P&ID / April 26, 2006

California Independent System Operator

Performance level

Performance Criteria:

• Performance Level B & C, including incorporation of PTO operational solutions

P&ID / April 26, 2006

California Independent System Operator

Load pocket & Effectiveness factors

Load Pocket:

• Fixed Boundary, including limited reference to published effectiveness factors

P&ID / April 26, 2006

California Independent System Operator

Definition of Effectiveness Factor

Effectiveness factor of a generator is calculated from the MW decrease is flow on the most limiting element (after the contingency has been taken) for a corresponding 100 MW increase in generation from that generator

P&ID / April 26, 2006

California Independent System Operator

Major Changes from last year’s studyThe introduction of Resource Adequacy Qualifying Capacity data

With the exception of the Bay Area study, the 2006 LCR Study utilized the historical output values of the available generation [based on the average generation output (between 2-5 pm) during the three hottest days in the summer] as the total dependable generation available. Given what the CAISO knows today, the historical output values utilized in the 2006 LCR study were lower when compared to the RA Qualifying Capacity data the CAISO utilized in the 2007 LCR Study. This difference was especially significant for areas with significant amounts of QF and hydro generation (i.e., Sierra and Humboldt). For the Bay Area study, the 2006 LCR study utilized the P max values which, when compared to the 2007 LCR study, were larger than the RA Qualifying Capacity data, especially due to QF and wind generation (see Bay Area study).

P&ID / April 26, 2006

California Independent System Operator

Total area requirement compared with sub-area requirements

The purpose of this report is to provide detailed local procurement information, as such each local area’s overall requirement has to be procured in a fashion that satisfies all of the sub-area requirements as well.

The role of sub-area requirements:Because each individual sub-area is a part of the interconnected electric system, the total for each local area is not simply a summation of the sub-area requirements (i.e., the sum of the parts does not necessarily equal the sum of the whole). For example, some sub-areas may overlap and therefore the same units can be counted toward both sub-area requirements. Of course some sub-areas requirements are directly counted toward the total requirements of a bigger local sub-area or the overall area. Other times the area has an overall requirement that exceeds the sum of the sub-area requirements. Each area is unique and detail analysis is provided in the report and each area’s presentation.

P&ID / April 26, 2006

California Independent System Operator

Can an area have a higherLCR requirement then load?

Yes.There should be no load drop for a category B condition. Take, for example, an area such as Sierra or Humboldt with has a limited import capability. Sierra has more ties, however some of them are exporting power therefore the net import is relatively small. Humboldt has few ties and 100% of the load must be served when one generator or a generator and a line are out of service. In both cases these contingencies (Rio Oso-Poe 230 kV with one of the Colgate units out or Cottonwood-Bridgeville with one of the Humboldt units out) account for the loss of ~25% of Qualifying Capacity in that area. One can see that if there were no ties the requirement would need to be at least 125% of load in the area. This is particularly true for areas where deficiencies in some sub-area have been added to the total existing generation in order to come up with the Total Area Requirement.Local load can NOT be subtracted from total LCR in order to come up with “Import Capability” into any one area. The LCR requirement represents the total “Capacity”needed in that area in order to respond to a large number of contingencies (including sub-area requirements). Not all of this capacity needs to be on-line simultaneously, some of it can be called upon after the first contingency has happened (especially in area with a lot of fast start units.

P&ID / April 26, 2006

California Independent System Operator

Zonal RequirementsThe ISO performed an assessment of the Zonal Capacity needs for year 2007. These results refer to the ISO control area only, they do not include requirements for other control areas like: LADWP, IID, SMUD-WAPA, TID or MID. Units need in order to comply with the Local Area Capacity Requirements fully count toward the Zonal Requirements. San Diego and LA Basin are situated in SP26, Kern in ZP26 and the rest in NP15.

Zone Load

Forecast (MW)

Generator Outages

(MW)

Single Worst Contingency

(MW)

(-)Import Capability

(MW)

Total Requirement

(MW) SP26 28,778 1,500 2,000 10,100 22,178 NP26=NP15+ZP26 21,518 2,500 1,160 5,348 19,830 NP15 Path 15 is not a binding constraint at this time

Load forecast = 1-in-5 Generator outages = average historical dataSingle worst contingency = ISO share of PDCI in the South, Diablo unit in the northImport Capability = ISO maximum historical import capability

P&ID / April 26, 2006

California Independent System Operator

Qualifying Capacity2007 LCR Requirement Based on Category B

(Option 1)

2007 LCR Requirement Based on Category C

with operating procedure (Option 2)

2006 Total LCR Req.

Local Area Name

QF/ Muni (MW)

Market(MW)

Total(MW)

Existing Capacity Needed

Deficiency

Total (MW)

Existing Capacity Needed

Deficiency

Total (MW) (MW)

Humboldt 73 133 206 202 0 202 202 0 202 162 North Coast / North Bay 158 861 1019 766** 0 766** 766** 0 766** 658

Sierra 1072 776 1848 1833 205 2038 1833 328 2161 1770*

Stockton 314 257 571 348 0 348 506 53 559 440*

Greater Bay 1314 5231 6545 4771 0 4771 5341 0 5341 6009 Greater Fresno 727 2185 2912 2760 0 2760 2797 4 2797 2837 *

Kern 797* LA Basin 3425 7033 10458 8843 0 8843 8843 0 8843 8127 San Diego 191 2741 2933 2781 0 2781 2781 0 2781 2620

Total 7274 19217 26492 22304 205 22509 23069 385 23450 23420 * Generation deficient areas (or with sub-area that are deficient) – deficiency included in LCR ** The North Coast/North Bay area requirement would have been higher by 80 MW, however a new operating procedure has been received, validated and implemented by PG&E and the CAISO.

How do I read this table ?

P&ID / April 26, 2006

California Independent System Operator

Table interpretationCategory C numbers are identical with Category B numbers

This area or sub-area requirement is driven by a Category B contingency, there is no Category C contingency with a higher requirement.

QF/Muni (MW) – Qualifying CapacityIncludes QF’s, Self-gen, Muni, State, Federal, nuclear and Wind generation.

Existing Capacity NeededThis represents the amount of capacity needed to be procured from the existing units in the area.

DeficiencyThis represents a proxy amount of extra capacity needed in order to comply with that category of the criteria by increasing the output of the most effective unit in the area (or sub-area) beyond it’s qualifying capacity until the problem has been solved.

What does it mean to be deficient in one area?Load drop needs to be implemented. For most category B contingencies there may be an existing scheme that drops load after the first contingency. For most category C contingencies the load most likely needs to be dropped at some reasonable time after the first contingency in order get the system into a safe operating zone and be able to support the loss of the next contingency and be within the existing applicable ratings.

RELIABILITY CRITERIA PART I - NERC/WECC PLANNING STANDARDS PART II - POWER SUPPLY ASSESSMENT POLICY PART III - MINIMUM OPERATING RELIABILITY CRITERIA PART IV - DEFINITIONS PART V - PROCESS FOR DEVELOPING AND APPROVING WECC STANDARDS

Western Electricity Coordinating Council

APRIL 2005

RELIABILITY CRITERIA PART I - NERC/WECC PLANNING STANDARDS PART II - POWER SUPPLY ASSESSMENT POLICY PART III - MINIMUM OPERATING RELIABILITY CRITERIA PART IV - DEFINITIONS

PART V - PROCESS FOR DEVELOPING AND APPROVING WECC STANDARDS

The WECC Reliability Criteria set forth the performance standards used by Western Electricity Coordinating Council and its Member Systems in assessing the reliability of the interconnected system. During 1996 the Council initiated an in-depth and comprehensive review of these Criteria. Recommendations made as a result of this review have been adopted by the Council and these Criteria have been revised accordingly. Definitions for key words and phrases used in the Council’s planning and operating criteria are included.

Western Electricity Coordinating Council

APRIL 2005

WESTERN ELECTRICITY COORDINATING COUNCIL

NERC/WECC PLANNING STANDARDS

PART I

Western Electricity Coordinating Council

WESTERN ELECTRICITY COORDINATING COUNCIL

NERC/WECC PLANNING STANDARDS

Revised April 10, 2003

NERC/WECC Planning StandardsContents

Preface................................................................................................................................................. 1

Foreword............................................................................................................................................ 1

Introduction ..................................................................................................................4

I. System Adequacy and Security ....................................................................................... 7Discussion.........................................................................................................................7A. Transmission Systems.................................................................................................9

WECC Standards ...............................................................................................9WECC Disturbance-Performance Table .........................................................12WECC Guides ..................................................................................................20Terms Used in the WECC Planning Standards ...............................................23

B. Reliability Assessment..............................................................................................26C. Facility Connection Requirements............................................................................29D. Voltage Support and Reactive Power .......................................................................32

WECC Standards .............................................................................................32WECC Guides ..................................................................................................33

E. Transfer Capability ...................................................................................................36F. Disturbance Monitoring............................................................................................44

II. System Modeling Data Requirements ...................................................................48Discussion.......................................................................................................................48A. System Data ..............................................................................................................49B. Generation Equipment ..............................................................................................55C. Facility Ratings .........................................................................................................59D. Actual and Forecast Demands ..................................................................................61E. Demand Characteristics (Dynamic)................................................................................ 65

III. System Protection and Control ...............................................................................67Discussion.......................................................................................................................67A. Transmission Protection Systems .............................................................................69

WECC Measure ...............................................................................................69B. Transmission Control Devices..................................................................................73

WECC Standard...............................................................................................73C. Generation Control and Protection ...........................................................................75D. Underfrequency Load Shedding ...............................................................................79E. Undervoltage Load Shedding ...................................................................................83F. Special Protection Systems.............................................................................................. 86

WECC Standards .............................................................................................86

IV. System Restoration ....................................................................................................90Discussion.......................................................................................................................90A. System Blackstart Capability....................................................................................91B. Automatic Restoration of Load....................................................................................... 93

References ....................................................................................................................................... 95

NERC/WECC Planning StandardsPreface and Foreword

NERC/WECC Planning Standards 1

Preface

This document merges the WECC Planning Standards into the NERC Planning Standards. TheWECC Planning Standards are indicated in italic and are preceded by headings WECC-S,WECC-M, or WECC-G, depending upon whether the differences are Standards, Measures orGuides. Certain aspects of the WECC standards are either more stringent or more specific thanthe NERC standards.

The NERC standards and associated Table I are applicable to all systems, without distinctionbetween internal and external systems. Unless otherwise stated, WECC standards and theassociated WECC Disturbance-Performance Table of Allowable Effects on Other Systems arenot applicable to internal systems.

It is intended that the WECC standards be periodically reviewed by the Reliability Subcommitteeas experience indicates, in accordance with WECC’s Process for Developing and ApprovingWECC Standards.

Foreword

This NERC Planning Standards report is the result of the NERC Engineering Committee’sefforts to address how NERC will carry out its reliability mission by establishing, measuringperformance relative to, and ensuring compliance with NERC Policies, Standards, Principles,and Guides. From the planning or assessment perspective, this report establishes Standards anddefines in terms of Measurements the required actions or system performance necessary tocomply with the Standards. This report also provides Guides that describe good planningpractices for consideration by all electric industry participants.

Mandatory compliance with the NERC Planning Standards is required of the NERC RegionalCouncils (Regions) and their members as well as all other electric industry participants if thereliability of the interconnected bulk electric systems is to be maintained in the competitiveelectricity environment. This report, however, does not address issues of implementation,compliance, and enforcement of the Standards. The timing and manner in which implementationand enforcement of and compliance with the NERC Planning Standards will be achieved has yetto be defined.

Background

At its September 1996 meeting, the NERC Board of Trustees unanimously accepted the report,Future Course of NERC, of its Future Role of NERC Task Force - II. This report outlinesseveral findings and recommendations on NERC’s future role and responsibilities in the light ofthe rapidly changing electric industry environment.

NERC/WECC Planning StandardsForeword

NERC/WECC Planning Standards 2

The report also concluded that NERC will carry out its reliability mission by:

• Establishing Reliability Policies, Standards, Principles, and Guides,• Measuring Performance Relative to NERC Policies, Standards, Principles, and Guides,

and• Ensuring Conformance to and Compliance with NERC Policies, Standards, Principles,

and Guides.

In accepting the Task Force’s report, the Board also directed the NERC Engineering Committeeand Operating Committee to develop appropriate implementation plans to address the recom-mendations in the Future Course of NERC report and to present these plans to the Board at itsJanuary 1997 meeting. The primary focus of the action plans and the initiatives from theEngineering Committee perspective was the development of Planning Standards and Guides.At its January 1997 meeting, the NERC Board of Trustees accepted the EngineeringCommittee’s November 1996 “Proposed Action Plan to Establish Revised and New NERCPlanning Standards and Guides” report. This action plan formed the basis for the developmentof NERC’s Planning Standards.

Standards Development

The Engineering Committee assigned the overall responsibility for the development andcoordination of the NERC Planning Standards to its Reliability Criteria Subcommittee (RCS).The Engineering Committee’s other subgroups were also called upon to provide major inputs toRCS in its Planning Standards development effort. These other subgroups included: theReliability Assessment Subcommittee, the Interconnections Dynamics Working Group, theMultiregional Modeling Working Group, the System Dynamics Database Working Group, theLoad Forecasting Working Group, and the Available Transfer Capability Implementation WorkingGroup.

In the development of the NERC Planning Standards, all proposed Standards, Measurements,and Guides were distributed for Regional and electric industry review prior to their submittal tothe Engineering Committee and Board for approval. The Engineering Committee recognized thatthe NERC Planning Standards would have to be more specific than in the past, and thatdifferences among the Regions would still need to be considered. It also recognizes that thedevelopment of Planning Standards will be an evolutionary process with continual additions,changes, and deletions.

The Engineering Committee extends its appreciation to the members of its subgroups and themembers of the Regions and electric industry sectors that commented on the proposed drafts ofthe NERC Planning Standards in their development phases. A substantial effort was expendedto develop the NERC Planning Standards in a very short time frame.

NERC/WECC Planning StandardsForeword

NERC/WECC Planning Standards 3

The NERC Planning Standards continue to define the reliability of the interconnected bulkelectric systems using the following two terms:

• Adequacy - The ability of the electric systems to supply the aggregate electricaldemand and energy requirements of their customers at all times, taking into accountscheduled and reasonably expected unscheduled outages of system elements.

• Security - The ability of the electric systems to withstand sudden disturbances such aselectric short circuits or unanticipated loss of system elements.

The Engineering Committee recognizes that this NERC Planning Standards report is the firstsuch industry effort to establish industry Planning Standards requiring mandatory complianceby the Regions, their members, and all other electric industry participants. This report alsodefines the specific actions or system performance that must be met to ensure compliance withthe Planning Standards.

The future challenge to the reliability of the electric systems will be to plan and operatetransmission systems so as to provide requested electric power transfers while maintainingoverall system reliability.

NERC/WECC Planning StandardsIntroduction

NERC/WECC Planning Standards 4

Electric system reliability begins with planning. The NERC Planning Standards state thefundamental requirements for planning reliable interconnected bulk electric systems. TheMeasurements define the required actions or system performance necessary to comply with theStandards. The Guides describe good planning practices and considerations.

With open access to the transmission systems in connection with the new competitive electricitymarket, all electric industry participants must accept the responsibility to observe and comply withthe NERC Planning Standards and to contribute to their development and continuedimprovement. That is, compliance with the NERC Planning Standards by the Regional Councils(Regions) and their members as well as all other electric industry participants is mandatory.

The Regions and their members along with all other electric industry participants are encouragedto consider and follow the Guides, which are based on the NERC Planning Standards. Theapplication of Guides is expected to vary to match load conditions and individual systemrequirements and characteristics.

Background

In January 1996, the NERC Board of Trustees formed a task force to reassess NERC’s futurerole, responsibilities, and organizational structure in light of the rapidly changing electric industryenvironment. The task force’s report, Future Course of NERC, accepted by the Board at itsSeptember 1996 meeting, concluded that NERC will carry out its reliability mission by:

• Establishing Reliability Policies, Standards, Principles, and Guides,• Measuring Performance Relative to NERC Policies, Standards, Principles, and Guides,

and• Ensuring Conformance to and Compliance with NERC Policies, Standards, Principles,

and Guides.

In January 1997, the Board voted unanimously to obligate its Regional and Affiliate Councils andtheir members to promote, support, and comply with all NERC Planning and Operating Policies.

Regional Planning Criteria and Guides

The Regions, subregions, power pools, and their members have the primary responsibility for thereliability of bulk electric supply in their respective areas. These entities also have theresponsibility to develop their own appropriate or more detailed planning and operating reliabilitycriteria and guides that are based on the Planning Standards and which reflect the diversity ofindividual electric system characteristics, geography, and demographics for their areas.

NERC/WECC Planning StandardsIntroduction

NERC/WECC Planning Standards 5

Therefore, all electric industry participants must also adhere to applicable Regional, subregional,power pool, and individual member planning criteria and guides. In those cases where Regional,subregional, power pool, and individual member planning criteria and guides are more restrictivethan the NERC Planning Standards, the more restrictive reliability criteria and guides must beobserved.

Responsibilities for Planning Standards, Measurements, and Guides

The NERC Board of Trustees approves the NERC Planning Standards, Measurements, andGuides to ensure that the interconnected bulk electric systems are planned reliably.

To assist the Board, the NERC Engineering Committee:

• Develops the NERC Planning Standards, Measurements, and Guides for theBoard’s approval, and

• Coordinates the NERC Planning Standards, Measurements, and Guides, asappropriate, with corresponding Operating Policies, Standards, Measurements, andGuides developed by the NERC Operating Committee.

The Regions, subregions, power pools, and their members:

• Develop planning criteria and guides that are applicable to their respective areas andwhich are in compliance with the NERC Planning Standards,

• Coordinate their planning criteria and guides with neighboring Regions and areas, and• Agree on planning criteria and guides to be used by intra- and interregional groups in

their planning and assessment activities.

Format of the NERC Planning Standards

The presentation of the Planning Standards in this report is based on the following generalformat:

• Introduction - Background and reason(s) for the Standard(s).• Standard - Statement of the specifics requiring compliance.• Measurement - Measure(s) of performance relative to the Standard.• Guides - Good planning practices and considerations that may vary for local

conditions.• Compliance and Enforcement - Not addressed in this report.

NERC/WECC Planning StandardsIntroduction

NERC/WECC Planning Standards 6

The NERC Planning Standards are in bold face type to distinguish them from the other sectionsof the report. In some cases, the Measurements of a Standard are multifaceted and addressseveral characteristics of the bulk electric systems or system components.

Definition of Bulk Electric System

The NERC Planning Standards, Measurements, and Guides in this report are intended toapply primarily to the bulk electric systems, also referred to as the interconnected transmissionsystems or networks. Because of the individual character of each of the Regions, it is recom-mended that each Region define those facilities that are to be included as its bulk electricsystems or interconnected transmission systems for which application of the PlanningStandards will be required. Any differences from the following Board definition of bulkelectric system shall be documented and reported to the NERC Engineering Committee prior tothe application or implementation of the Planning Standards in this report.

The NERC Board of Trustees at its April 1995 meeting approved a definition for the bulkelectric system as follows:

“The bulk electric system is a term commonly applied to that portion of anelectric utility system, which encompasses the electrical generation resources,transmission lines, interconnections with neighboring systems, and associatedequipment, generally operated at voltages of 100 kV or higher.”

This definition is included in the May 1995 NERC brochure on “Planning of the Bulk ElectricSystems” prepared by a task force of the Engineering Committee.

A system facility, element, or component has been defined as any generating unit, transmissionline, transformer, or piece of electrical equipment comprising an electric system. This definition isincluded in the May 1995 NERC Transmission Transfer Capability reference document.

Compliance With NERC Planning Standards

The interconnected bulk electric systems in the United States, Canada, and the northern portion ofBaja California, Mexico are comprised of many individual systems, each with its own electricalcharacteristics, set of customers, and geographic, weather, and economic conditions, andregulatory and political climates. By their very nature, the bulk electric systems involve multipleparties. Since all electric systems within an integrated network are electrically connected,whatever one system does can affect the reliability of the other systems. Therefore, to maintainthe reliability of the bulk electric systems or interconnected transmission systems or networks, theRegions and their members and all electric industry participants must comply with the NERCPlanning Standards.

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The interconnected transmission systems are the principal media for achieving reliable electricsupply. They tie together the major electric system facilities, generation resources, and customerdemand centers. These systems must be planned, designed, and constructed to operate reliablywithin thermal, voltage, and stability limits while achieving their major purposes. Thesepurposes are to:

• Deliver Electric Power to Areas of Customer Demand - Transmission systemsprovide for the integration of electric generation resources and electric system facilitiesto ensure the reliable delivery of electric power to continuously changing customerdemands under a wide variety of system operating conditions.

• Provide Flexibility for Changing System Conditions - Transmission capacity mustbe available on the interconnected transmission systems to provide flexibility to handlethe shift in facility loadings caused by the maintenance of generation and transmissionequipment, the forced outages of such equipment, and a wide range of other systemvariable conditions, such as construction delays, higher than expected customerdemands, and generating unit fuel shortages.

• Reduce Installed Generating Capacity - Transmission interconnections withneighboring electric systems allow for the sharing of generating capacity throughdiversity in customer demands and generator availability, thereby reducing investmentin generation facilities.

• Allow Economic Exchange of Electric Power Among Systems - Transmissioninterconnections between systems, coupled with internal system transmission facilities,allow for the economic exchange of electric power among all systems and industryparticipants. Such economy transfers help to reduce the cost of electric supply tocustomers.

Electric power transfers have a significant effect on the reliability of the interconnectedtransmission systems, and must be evaluated in the context of the other functions performed bythese interconnected systems. In some areas, portions of the transmission systems are beingloaded to their reliability limits as the uses of the transmission systems change relative to thosefor which they were planned, and as opposition to new transmission prevents facilities from beingconstructed as planned. Efforts by all industry participants to minimize costs will also continue toencourage, within safety and reliability limits, maximum loadings on the existing transmissionsystems.

The new competitive electricity environment is fostering an increasing demand for transmissionservices. With this focus on transmission and its ability to support competitive electric powertransfers, all users of the interconnected transmission systems must understand the electricallimitations of the transmission systems and the capability of these systems to reliably support awide variety of transfers. The future challenge will be to plan and operate transmission systemsthat provide the requested electric power transfers while maintaining overall system reliability.

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All electric utilities, transmission providers, electricity suppliers, purchasers, marketers, brokers,and society at large benefit from having reliable interconnected bulk electric systems. To ensurethat these benefits continue, all industry participants must recognize the importance of planningthese systems in a manner that promotes reliability.

The NERC Planning Standards, Measurements, and Guides pertaining to System Adequacyand Security (I.) are provided in the following sections:

A. Transmission SystemsB. Reliability AssessmentC. Facility Connection RequirementsD. Voltage Support and Reactive PowerE. Transfer CapabilityF. Disturbance Monitoring

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Introduction

The fundamental purpose of the interconnected transmission systems is to move electric powerfrom areas of generation to areas of customer demand (load). These systems should be capable ofperforming this function under a wide variety of expected system conditions (e.g., forced andplanned equipment outages, continuously varying customer demands) while continuing to operatereliably within equipment and electric system thermal, voltage, and stability limits.

Electric systems must be planned to withstand the more probable forced and planned outagesystem contingencies at projected customer demand and projected electricity transfer levels.

Extreme but less probable contingencies measure the robustness of the electric systems andshould be evaluated for risks and consequences. The risks and consequences of these con-tingencies should be reviewed by the entities responsible for the reliability of the interconnectedtransmission systems. Actions to mitigate or eliminate the risks and consequences are at thediscretion of those entities.

The ability of the interconnected transmission systems to withstand probable and extreme con-tingencies must be determined by simulated testing of the systems as prescribed in these I.A.Standards on Transmission Systems.

System simulations and associated assessments are needed periodically to ensure that reliablesystems are developed with sufficient lead time and continue to be modified or upgraded asnecessary to meet present and future system needs.

Standards

S1. The interconnected transmission systems shall be planned, designed, and constructedsuch that with all transmission facilities in service and with normal (pre-contingency)operating procedures in effect, the network can deliver generator unit output to meetprojected customer demands and projected firm (non-recallable reserved)transmission services, at all demand levels over the range of forecast system demands,under the conditions defined in Category A of Table I (attached).

Transmission system capability and configuration, reactive power resources,protection systems, and control devices shall be adequate to ensure the systemperformance prescribed in Table I.

S2. The interconnected transmission systems shall be planned, designed, and constructedsuch that the network can be operated to supply projected customer demands andprojected firm (non-recallable reserved) transmission services, at all demand levels,under the conditions of the contingencies as defined in Category B of Table I(attached).

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Transmission system capability and configuration, reactive power resources,protection systems, and control devices shall be adequate to ensure the systemperformance prescribed in Table I.

The transmission systems also shall be capable of accommodating planned bulkelectric equipment outages and continuing to operate within thermal, voltage, andstability limits under the contingency conditions as defined in Category B of Table I(attached).

S3. The interconnected transmission systems shall be planned, designed, and constructedsuch that the network can be operated to supply projected customer demands andprojected firm (non-recallable reserved) transmission services, at all demand levelsover the range of forecast system demands, under the conditions of the contingenciesas defined in Category C of Table I (attached). The controlled interruption ofcustomer demand, the planned removal of generators, or the curtailment of firm(non-recallable reserved) power transfers may be necessary to meet this standard.

Transmission system capability and configuration, reactive power resources,protection systems, and control devices shall be adequate to ensure the systemperformance prescribed in Table I.

The transmission systems also shall be capable of accommodating planned bulkelectric equipment outages and continuing to operate within thermal, voltage, andstability limits under the conditions of the contingencies as defined in Category C ofTable I (attached).

S4. The interconnected transmission systems shall be evaluated for the risks andconsequences of a number of each of the extreme contingencies that are listed underCategory D of Table I (attached).

WECC-S1 In addition to NERC Table I, WECC Member Systems shall comply with theWECC Disturbance-Performance Table of Allowable Effects on Other Systemscontained in this section when planning the Western Interconnection. TheWECC Disturbance-Performance Table does not apply internal to a WECCMember System.

WECC-S2 The NERC Category C.5 initiating event of a non-three phase fault with normalclearing shall also apply to the common mode contingency of two adjacentcircuits on separate towers unless the event frequency is determined to be lessthan one in thirty years.

WECC-S3 The common mode simultaneous outage of two generator units connected tothe same switchyard, not addressed by the initiating events in NERCCategory C, shall not result in cascading.

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WECC-S4 The loss of multiple bus sections as a result of a failure or delayed clearing of abus tie or bus sectionalizing breaker shall meet the performance specified forCategory D of the WECC Disturbance-Performance Table.

WECC-S5 For contingencies involving existing or planned facilities, the Table W-1performance category can be adjusted based on actual or expected performance(e.g. event outage frequency and consideration of impact) after going throughthe WECC Phase I Probabilistic Based Reliability Criteria (PBRC)Performance Category Evaluation (PCE) Process.

WECC-S6 Any contingency adjusted to Category D must not result in a cascading outageunless the MTBF is greater than 300 years (frequency less than 0.0033outages/year) or the initiating disturbances and corresponding impacts areconfined to either a radial system or a local network.

WECC-S7 For any event that has actually resulted in cascading, action must be taken sothat future occurrences of the event will not result in cascading, or it must gothrough the PBRC process and demonstrate that the MTBF is greater than 300years (frequency less than 0.0033 outages/year).

WECC-S8 The WECC Planning Standards require systems to meet the same performancecategory for unsuccessful reclosing as that required for the initiatingdisturbance without reclosing.

WECC-S9 To the extent permitted by NERC Planning Standards, individual systems or agroup of systems may apply standards that differ from the WECC specificstandards in Table W-1 for internal impacts. If the individual standards areless stringent, other systems are permitted to have the same impact on that partof the individual system for the same category of disturbance. If thesestandards are more stringent, these standards may not be imposed on othersystems. This does not relieve the system or group of systems from WECCstandards for impacts on other systems.

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WECC DISTURBANCE-PERFORMANCE TABLEOF ALLOWABLE EFFECTS ON OTHER SYSTEMS

NERC andWECC

Categories

Outage Frequency Associatedwith the Performance Category(outage/year)

TransientVoltageDipStandard

MinimumTransientFrequencyStandard

PostTransientVoltageDeviationStandard(See Note 2)

A Not Applicable Nothing in addition to NERC

B ≥ 0.33 Not to exceed25% at load buses

or 30% at non-load buses.

Not to exceed20% for more

than 20 cycles atload buses.

Not below 59.6Hz for 6 cycles ormore at a load bus.

Not to exceed 5% at any bus.

C 0.033 – 0.33 Not to exceed30% at any bus.

Not to exceed20% for more

than 40 cycles atload buses.

Not below 59.0Hz for 6 cycles ormore at a load bus.

Not to exceed 10% at any bus.

D < 0.033 Nothing in addition to NERC

Notes:

1. The WECC Disturbance-Performance Table applies equally to either a system with allelements in service, or a system with one element removed and the system adjusted.

2. As an example in applying the WECC Disturbance-Performance Table, a Category Bdisturbance in one system shall not cause a transient voltage dip in another system that isgreater than 20% for more than 20 cycles at load buses, or exceed 25% at load buses or30% at non-load buses at any time other than during the fault.

3. Additional voltage requirements associated with voltage stability are specified in Standard I-D. If it can be demonstrated that post transient voltage deviations that are less than thevalues in the table will result in voltage instability, the system in which the disturbanceoriginated and the affected system(s) should cooperate in mutually resolving the problem.

Table W-1

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4. Refer to Figure W-1 for voltage performance parameters.

5. Load buses include generating unit auxiliary loads.

6. To reach the frequency categories shown in the WECC Disturbance-Performance Table forCategory C disturbances, it is presumed that some planned and controlled islanding hasoccurred. Underfrequency load shedding is expected to arrest this frequency decline andassure continued operation within the resulting islands.

7. For simulation test cases, the interconnected transmission system steady state loadingconditions prior to a disturbance should be appropriate to the case. Disturbances should besimulated at locations on the system that result in maximum stress on other systems. Relayaction, fault clearing time, and reclosing practice should be represented in simulationsaccording to the planning and operation of the actual or planned systems. When simulatingpost transient conditions, actions are limited to automatic devices and no manual action is tobe assumed.

Figure W-1

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Measurements

M1. Entities responsible for the reliability of the interconnected transmission systemsshall ensure that the system responses for Standard S1 are as defined in CategoryA (no contingencies) of Table I (attached) and summarized below:

a. Line and equipment loadings shall be within applicable thermal ratinglimits.

b. Voltage levels shall be maintained within applicable limits.c. All customer demands shall be supplied, and all projected firm (non-

recallable reserved) transfers shall be maintained.d. Stability of the network shall be maintained.

Assessment RequirementsEntities responsible for the reliability of interconnected transmission systems(e.g., transmission owners, independent system operators (ISOs), regionaltransmission organizations (RTOs), or other groups responsible for planning thebulk electric systems) shall annually assess the performance of their systems inmeeting Standard S1.

Valid assessments shall include the attributes listed below, and as more fullydescribed in the following paragraphs:

1. Be supported by a current or past study that addresses the plan year beingassessed.

2. Address any planned upgrades needed to meet the performancerequirements of Category A.

3. Be conducted for near-term (years one through five) and longer-term (yearssix through ten) planning horizons.

System performance assessments based on system simulation testing shall showthat with all planned facilities in service (no contingencies), established normal(pre-contingency) operating procedures in place, and with all projected firmtransfers modeled, line and equipment loadings are within applicable thermalratings, voltages are within applicable limits, and the systems are stable forselected demand levels over the range of forecast system demands.

Assessments shall include the effects of existing and planned reactive powerresources to ensure that adequate reactive resources are available to meet thesystem performance as defined in Category A of Table I.

Assessments shall be conducted annually and shall cover critical systemconditions and study years as deemed appropriate by the responsible entity. Theyshall be conducted for near- (years one through five) and longer-term (years sixthrough ten) planning horizons. Simulation testing of the systems need not be

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conducted annually if changes to system conditions do not warrant such analyses.Simulation testing beyond the five-year horizon should be conducted as needed toaddress identified marginal conditions that may have longer lead-time solutions.

Corrective Plan RequirementsWhen system simulations indicate an inability of the systems to respond asprescribed in this Measurement (M1), responsible entities shall provide a writtensummary of their plans, including a schedule for implementation, to achieve therequired system performance throughout the planning horizon as described above.Plan summaries shall discuss expected required in-service dates of facilities, andshall consider lead times necessary to implement plans. Identified systemfacilities for which sufficient lead times exist need not have detailedimplementation plans, and shall be reviewed for continuing need in subsequentannual assessments.

Reporting RequirementsThe documentation of results of these reliability assessments and corrective plansshall annually be provided to the entities’ respective NERC Region(s), as requiredby the Region. Each Region, in turn, shall annually provide a summary (perStandard I.B. S1. M1) of its Regional reliability assessments to the NERCPlanning Committee (or its successor).

M2. Entities responsible for the reliability of the interconnected transmission systemsshall ensure that the system responses for Standard S2 contingencies are asdefined in Category B (event resulting in the loss of a single element) of Table I(attached) and summarized below:

a. Line and equipment loadings shall be within applicable rating limits.b. Voltage levels shall be maintained within applicable limits.c. No loss of customer demand (except as noted in Table I, footnote b)

shall occur, and no projected firm (non-recallable reserved) transfersshall be curtailed.

d. Stability of the network shall be maintained.e. Cascading outages shall not occur.

1. Assessments shall be supported by a current or past study that addresses theplan year being assessed.

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2. Assessments shall address any planned upgrades needed to meet theperformance requirements of Category B.

3. Assessments shall be conducted for near-term (years one through five) andlonger-term (years six through ten) planning horizons.

System performance assessments based on system simulation testing shall showthat for system conditions where the initiating event results in the loss of a singlegenerator, transmission circuit, or bulk system transformer, and with all projectedfirm transfers modeled, line and equipment loadings are within applicable thermalratings, voltages are within applicable limits, and the systems are stable forselected demand levels over the range of forecast system demands. No plannedloss of customer demand nor curtailment of projected firm transfers shall benecessary to meet these performance requirements, except as noted in footnote bof Table I. This system performance shall be achieved for the describedcontingencies of Category B of Table I.

Assessments shall consider all contingencies applicable to Category B, but shallsimulate and evaluate only those that would produce the more severe systemresults or impacts. The rationale for the contingencies selected for evaluation shallbe available as supporting information and shall include an explanation of whythe remaining simulations would produce less severe system results.

Assessments shall include the effects of existing and planned facilities, includingreactive power resources to ensure that adequate reactive resources are availableto meet the system performance as defined in Category B of Table I. Assessmentsshall also include the effects of existing and planned protection systems andcontrol devices, including any backup or redundant protection systems, to ensurethat protection systems and control devices are sufficient to meet the systemperformance as defined in Category B of Table I.

The systems must be capable of meeting Category B requirements whileaccommodating the planned (including maintenance) outage of any bulk electricequipment (including protection systems or their components) at those demandlevels for which planned (including maintenance) outages are performed.

Assessments shall be conducted annually and shall cover critical systemconditions and study years as deemed appropriate by the responsible entity. Theyshall also be conducted for near- (years one through five) and longer-term (yearssix through ten) planning horizons. Simulation testing of the systems need not beconducted annually if changes to system conditions do not warrant such analyses.Simulation testing beyond the five-year horizon should be conducted as needed toaddress identified marginal conditions that may have longer lead-time solutions.

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Corrective Plan RequirementsWhen system simulations indicate an inability of the systems to respond asprescribed in this Measurement (M2), responsible entities shall provide a writtensummary of their plans, including a schedule for implementation, to achieve therequired system performance throughout the planning horizon as described above.Plan summaries shall discuss expected required in-service dates of facilities, andshall consider lead times necessary to implement plans. Identified systemfacilities for which sufficient lead times exist need not have detailedimplementation plans, and shall be reviewed for continuing need in subsequentannual assessments.

M3. Entities responsible for the reliability of the interconnected transmission systemsshall ensure that the system responses for Standard S3 are as defined in CategoryC (event(s) resulting in the loss of two or more elements) of Table I (attached)and summarized below:

a. Line and equipment loadings shall be within applicable thermal ratinglimits.

b. Voltage levels shall be maintained within applicable limits.c. Planned (controlled) interruption of customer demand or generation (as

noted in Table I, footnote d) may occur, and contracted firm (non-recallable reserved) transfers may be curtailed.

d. Stability of the network shall be maintained.e. Cascading outages shall not occur.

Assessment RequirementsEntities responsible for the reliability of the interconnected transmission systems(e.g., transmission owners, independent system operators (ISOs), regionaltransmission organizations (RTOs), or other groups responsible for planning thebulk electric systems) shall annually assess the performance of their systems inmeeting Standard S3.

Valid assessments shall include the attributes listed below, and as more fullydescribed in the following paragraphs:

1. Assessments shall be conducted for near-term (years one through five) andlonger-term (years six through ten) planning horizons.

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2. Assessments of the near-term planning horizon shall be supported by a currentor past study that addresses the plan year being assessed. For assessments ofthe longer-term planning horizon, a current or past study that addresses theplan year being assessed shall only be required if marginal conditions thatmay have longer lead-time solutions have been identified in the near-termassessment.

3. Assessments shall address any planned upgrades needed to meet theperformance requirements of Category C.

System performance assessments based on system simulation testing shall showthat for system conditions where (See Table I Category C)

1. The initiating event results in the loss of two or more elements, or2. Two separate events occur resulting in two or more elements out of service

with time for manual system adjustments between events,

and with all projected firm transfers modeled, line and equipment loadings arewithin applicable thermal ratings, voltages are within applicable limits, and thesystems are stable for selected demand levels over the range of forecast systemdemands. Planned outages of customer demand or generation (as noted in TableI, footnote d) may occur, and contracted firm (non-recallable reserved) transfersmay be curtailed. This system performance shall be achieved for the describedcontingencies of Category C of Table I.

Assessments shall consider all contingencies applicable to Category C, but shallsimulate and evaluate only those that would produce the more severe systemresults or impacts. The rationale for the contingencies selected for evaluationshall be available as supporting information and shall include an explanation ofwhy the remaining simulations would produce less severe system results.

Assessments shall include the effects of existing and planned facilities, includingreactive power resources to ensure that adequate reactive resources are availableto meet the system performance as defined in Category C of Table I.Assessments shall also include the effects of existing and planned protectionsystems and control devices, including any backup or redundant protectionsystems, to ensure that protection systems and control devices are sufficient tomeet the system performance as defined in Category C of Table I.

The systems must be capable of meeting Category C requirements whileaccommodating the planned (including maintenance) outage of any bulk electricequipment (including protection systems or their components) at those demandlevels for which planned (including maintenance) outages are performed.

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Assessments shall be conducted annually and shall cover critical systemconditions and study years as deemed appropriate by the responsible entity. Theyshall also be conducted for near (years one through five) and longer-term (yearssix through ten) planning horizons. Simulation testing of the systems need not beconducted annually if changes to system conditions do not warrant such analyses.Simulation testing beyond the five-year horizon should be conducted as needed toaddress identified marginal conditions that may have longer lead-time solutions.

Corrective Plan RequirementsWhen system simulations indicate an inability of the systems to respond asprescribed in this Measurement (M3), responsible entities shall provide a writtensummary of their plans, including a schedule for implementation, to achieve therequired system performance throughout the planning horizon as described above.Plan summaries shall discuss expected required in-service dates of facilities, andshall consider lead times necessary to implement plans. Identified systemfacilities for which sufficient lead times exist need not have detailedimplementation plans, and shall be reviewed for continuing need in subsequentannual assessments.

M4. Entities responsible for the reliability of the interconnected transmission systemsshall assess the risks and system responses for Standard S4 as defined in CategoryD of Table I (attached).

Valid assessments shall include the attributes listed below, and as more fullydescribed in the following paragraphs:

1. Assessments shall be conducted for near-term (years one through five)planning horizons.

2. Assessments shall be supported by a current or past study that addresses theplan year being assessed.

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System performance assessments based on system simulation testing shallevaluate system conditions of Table I Category D, with all projected firmtransfers modeled.

Assessments shall consider all contingencies applicable to Category D, but shallsimulate and evaluate only those that would produce the more severe systemresults or impacts. The rationale for the contingencies selected for evaluation shallbe available as supporting information and shall include an explanation of whythe remaining simulations would produce less severe system results.

Assessments shall include the effects of existing and planned facilities, includingreactive power resources, and shall include the effects of existing and plannedprotection systems and control devices, including any backup or redundantprotection systems.

Assessments shall consider the planned (including maintenance) outage of anybulk electric equipment (including protection systems or their components) atthose demand levels for which planned (including maintenance) outages areperformed when evaluating the effects of Category D events.

Assessments shall be conducted annually and shall cover critical systemconditions and study years as deemed appropriate by the responsible entity. Theyshall be conducted for near-term (years one through five) planning horizons.Simulation testing of the systems need not be conducted annually if changes tosystem conditions do not warrant such analyses.

Corrective Plan RequirementsNone required.

Reporting RequirementsThe documentation of results of these reliability assessments and mitigationmeasures shall annually be provided to the entities’ respective NERC Region(s),as required by the Region. Each Region, in turn, shall annually provide asummary (per Standard I.B. S1. M1) of its Regional reliability assessments to theNERC Planning Committee (or its successor).

M5. Entities responsible for the reliability of the interconnected transmission systemsshall document their assessment activities in compliance with the I.B. Standard onReliability Assessment to ensure that their respective systems are in compliancewith these I.A. Standards on Transmission Systems. This documentation shall beprovided to NERC on request. (S1, S2, S3, and S4)

Guides

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G1. The planning, development, and maintenance of transmission facilities should becoordinated with neighboring systems to preserve the reliability benefits ofinterconnected operations.

G2. Studies affecting more than one system owner or user should be conducted on ajoint interconnected system basis.

G3. The interconnected transmission systems should be designed and operated suchthat reasonable and foreseeable contingencies do not result in the loss orunintentional separation of a major portion of the network.

G4. The interconnected transmission systems should provide flexibility in switchingarrangements, voltage control, and other protection system measures to ensurereliable system operation.

G5. The assessment of transmission system capability and the need for systemenhancements should take into account the maintenance outage plans of thetransmission facility owners. These maintenance plans should be coordinated onan intra- and interregional basis.

G6. The interconnected transmission systems should be planned to avoid excessivedependence on any one transmission circuit, structure, right-of-way, or substation.

G7 Reliability assessments should examine post-contingency steady-state conditionsas well as stability, overload, cascading, and voltage collapse conditions. Pre-contingency system conditions chosen for analysis should include contracted firm(non-recallable reserved) transmission services.

G8. Annual updates to the transmission assessments should be performed, asappropriate, to reflect anticipated significant changes in system conditions.

G9. Extreme contingency evaluations should be conducted to measure the robustnessof the interconnected transmission systems and to maintain a state of preparednessto deal effectively with such events. Although it is not practical (and in somecases not possible) to construct a system to withstand all possible extremecontingencies without cascading, it is desirable to control or limit the scope ofsuch cascading or system instability events and the significant economic andsocial impacts that can result.

G10. It may be appropriate to conduct the extreme contingency assessments on acoordinated intra- or interregional basis so that all potentially affected entities areaware of the possibility of cascading or system instability events.

WECC-G1 The contingencies specified for each Category in the NERC table and theoutage frequency range provided in the WECC table provide a basis for

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estimating performance categories for disturbances that are not in the NERCTable or for disturbances that have sufficient data available to estimate theirprobability of occurrence.

WECC-G2 Each system should provide sufficient transmission capacity within its system toserve its load and meet its transmission obligations to others without undulyrelying on or without imposing an undue degradation of reliability on any othersystem, unless pursuant to prior agreement with the system(s) so affected. Eachsystem should provide sufficient transmission capacity, by ownership oragreement, for scheduling power transfers between its system and any othersystem. In transferring such power there should be no undue degradation ofreliability on any system not a party to the transfer.

WECC-G3 Each system should plan its system with adequate transfer capability so that itspower transfers will not have an undue loop flow impact on other systems, andso that planned schedules do not depend on opposing loop flow to keep actualflows within the path transfer capability. A system adding facilities shouldrecognize that the addition itself could result in a component of loop flow thatshould be accommodated. Loop flow is an inherent characteristic ofinterconnected AC transmission systems and the mere presence of loop flow oncircuits other than those of the transfer path is not necessarily an indication ofa problem in planning or in scheduling practices.

WECC-G4 An initiating event of a three phase fault may be used for screeningcontingencies of two adjacent circuits. However, the required performance willbe as specified in Table I for category C5 (Non three phase fault with NormalClearing: Double Circuit Tower-line) events. Simulations meeting the criteriawith a three-phase fault may be assumed to meet the criteria with a non-threephase fault and normal clearing.

WECC-G5 Considerations in determining the probability of occurrence of an outage of twoadjacent circuits on separate towers should include line design; length;location, environmental factors; outage history; operational guidelines; andseparation between circuits.

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TERMS USED IN THE WECC PLANNING STANDARDS

Post Transient Voltage Deviation

In the context of these Planning Standards, post transient voltage deviation refers to “voltagedrop” not “voltage rise,” and the post-transient time frame is considered to be one to threeminutes after a system disturbance occurs. This allows available automatic voltage supportmeasures to take place, but does not allow the effects of operator manual actions or AreaGeneration Control response. The recommended simulation is a post transient power flow thatsimulates all automatic action but not manual actions and not area interchange control. Thepost transient voltage deviation standards do not fully identify all potential voltage collapseproblems. Voltage collapse standards are discussed in greater depth in Standard I D.

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Table I. Transmission Systems Standards — Normal and Contingency ConditionsCategory Contingencies System Limits or Impacts

Initiating Event(s) and Contingency Element(s) Elements

Out of ServiceThermalLimits

VoltageLimits

SystemStable

Loss of Demand orCurtailed Firm Transfers

Cascadingc

Outages

A - No Contingencies All Facilities in Service None Applicable

Rating a(A/R)

Applicable

Rating a(A/R)

Yes No No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault, with Normal Clearing:1. Generator2. Transmission Circuit3. Transformer

Loss of an Element without a Fault.

SingleSingleSingleSingle

A/RA/RA/RA/R

YesYesYesYes

No b

NoNoNoNo

B – Event resulting inthe loss of a singleelement.

Single Pole Block, Normal Clearing f

:4. Single Pole (dc) Line Single A/R A/R Yes No

bNo

SLG Fault, with Normal Clearing f

:1. Bus Section2. Breaker (failure or internal fault)

MultipleMultiple

A/RA/R

YesYes

Planned/Controlledd

Planned/Controlledd No

SLG or 3Ø Fault, with Normal Clearing f

, Manual System Adjustments,

followed by another SLG or 3Ø Fault, with Normal Clearing f

:3. Category B (B1, B2, B3, or B4) contingency, manual system

adjustments, followed by another Category B (B1, B2, B3, or B4)contingency

Multiple A/R A/R Yes Planned/Controlledd

Bipolar Block, with Normal Clearing f

:4. Bipolar (dc) Line

Fault (non 3Ø), with Normal Clearing f

5. Any two circuits of a multiple Circuit towerline g

Multiple

A/R

Yes

Planned/Controlledd

C – Event(s) resultingin the loss of two ormore (multiple)elements.

SLG Fault, with Delayed Clearing f

(stuck breaker or protection systemfailure):

6. Generator 8. Transformer7. Transmission Circuit 9. Bus Section

MultipleMultiple

A/RA/R

YesYes

Planned/Controlledd

Planned/Controlledd No

NERC/WECC Planning StandardsI. System Adequacy and Security A. Transmission Systems

NERC/WECC Planning Standards 25

3Ø Fault, with Delayed Clearing f (stuck breaker or protection systemfailure):

1. Generator 3. Transformer2. Transmission Circuit 4. Bus Section

3Ø Fault, with Normal Clearing f:5. Breaker (failure or internal fault)

D e – Extreme eventresulting in two ormore (multiple)elements removed orcascading out ofservice

Other:6. Loss of towerline with three or more circuits7. All transmission lines on a common right-of-way8. Loss of a substation (one voltage level plus transformers)9. Loss of a switching station (one voltage level plus transformers)

10. Loss of all generating units at a station 11. Loss of a large load or major load center 12. Failure of a fully redundant special protection system (or remedial

action scheme) to operate when required 13. Operation, partial operation, or misoperation of a fully redundant

special protection system (or remedial action scheme) in response toan event or abnormal system condition for which it was not intendedto operate

14. Impact of severe power swings or oscillations from disturbances inanother Regional Council.

Evaluate for risks and consequences.

• May involve substantial loss of customer demand and generation in a widespreadarea or areas.

• Portions or all of the interconnected systems may or may not achieve a new, stableoperating point.

• Evaluation of these events may require joint studies with neighboring systems.

Footnotes to Table I.

a) Applicable rating (A/R) refers to the applicable normal and emergency facility thermal rating or system voltage limit as determined and consistently applied by the system or facility owner.Applicable ratings may include emergency ratings applicable for short durations as required to permit operating steps necessary to maintain system control. All ratings must be establishedconsistent with applicable NERC Planning Standards addressing facility ratings.

b) Planned or controlled interruption of electric supply to radial customers or some local network customers, connected to or supplied by the faulted element or by the affected area, may occur incertain areas without impacting the overall security of the interconnected transmission systems. To prepare for the next contingency, system adjustments are permitted, including curtailmentsof contracted firm (non-recallable reserved) electric power transfers.

c) Cascading is the uncontrolled successive loss of system elements triggered by an incident at any location. Cascading results in widespread service interruption which cannot be restrained fromsequentially spreading beyond an area predetermined by appropriate studies.

d) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers (load shedding), the planned removal from service of certain generators,and/or the curtailment of contracted firm (non-recallable reserved) electric power transfers may be necessary to maintain the overall security of the interconnected transmission systems.

e) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission planning entity(ies) will be selected for evaluation. It is not expected that allpossible facility outages under each listed contingency of Category D will be evaluated.

f) Normal clearing is when the protection system operates as designed and the fault is cleared in the time normally expected with proper functioning of the installed protection systems. Delayedclearing of a fault is due to failure of any protection system component such as a relay, circuit breaker, or current transformer (CT), and not because of an intentional design delay.

g) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station entrance, river crossings) in accordance with Regional exemption criteria

NERC/WECC Planning StandardsI. System Adequacy and Security B. Reliability Assessment

NERC/WECC Planning Standards 26

Introduction

NERC, through its Planning Committee (or successor group(s)), reviews and assesses the overallreliability (adequacy and security) of the interconnected bulk electric systems, both existing andas planned, to ensure that each Region (subregion) complies with the NERC Planning Standardsand its own Regional planning criteria.

NERC also conducts special reliability assessments on a Regional, interregional, andInterconnection basis as conditions warrant or as requested by the NERC Planning Committee orBoard of Trustees. Such special reliability assessments may include, among others, securityassessments, operational assessments, evaluations of emergency response preparedness,adequacy of fuel supply and hydro conditions, reliability impacts of new or proposedenvironmental rules and regulations, and reliability impacts of new or proposed legislation thataffects, has affected, or has the potential to affect the adequacy of the interconnected bulkelectric systems in North America.

To carry out these reviews and assessments of the overall reliability of the interconnected bulkelectric systems, NERC (and its Planning Committee or successor group(s)) must have sufficientdata and input from the Regions to prepare and publish NERC’s annual seasonal (summer andwinter) and longer-range assessments of the reliability of the interconnected bulk electricsystems. Additional data may also be required for the special reliability assessments.

NERC's adequacy and security assessments must ensure the requirements stated in eachRegion’s planning criteria and the NERC Planning Standards are met.

The Regions must also assess their Regional bulk electric system reliability within the context ofthe interconnected networks. Therefore, the Region and its members must coordinate theirassessment efforts not only within their Region, but also with neighboring systems and Regions.

Standards

S1. The overall reliability (adequacy and security) of the Regions’ interconnected bulkelectric systems, both existing and as planned, shall comply with the NERCPlanning Standards and each Region's respective Regional planning criteria.

Measurements

M1. Each Region shall annually conduct reliability assessments of its respectiveexisting and planned Regional bulk electric system (generation and transmissionfacilities) for: 1) seasonal (winter and summer of the current year) conditions orother current-year system conditions as deemed appropriate by the Region, and 2)near-term (years one through five) and longer-term (years six through ten)planning horizons. For the near term, detailed assessments shall be conducted. For

NERC/WECC Planning StandardsI. System Adequacy and Security B. Reliability Assessment

NERC/WECC Planning Standards 27

the longer term, assessment shall focus on the analysis of trends in resources andtransmission adequacy, other industry trends and developments, and reliabilityconcerns.

Similarly, the Regions shall also annually conduct interregional reliabilityassessments to ensure that the Regional bulk electric systems are planned anddeveloped on a coordinated or joint basis to preserve the adequacy and security ofthe interconnected bulk electric systems.

Regional and interregional reliability assessments shall demonstrate that theperformance of these systems are in compliance with NERC Standard I.A andrespective Regional transmission and generation criteria. These assessments shallalso identify key reliability issues and the risks and uncertainties affectingadequacy and security.

Regional and interregional seasonal, near-term, and longer-term reliabilityassessments shall be provided to NERC on an annual basis.

In addition, special reliability assessments shall also be performed as requested bythe NERC Planning Committee or Board of Trustees under their specificdirections and criteria. Such assessments may include, among others, securityassessments, operational assessments, evaluations of emergency responsepreparedness, adequacy of fuel supply and hydro conditions, reliability impacts ofnew or proposed environmental rules and regulations, and reliability impacts ofnew or proposed legislation that affects, has affected, or has the potential to affectthe adequacy of the interconnected bulk electric systems in North America.

M2. Each Region shall provide, as requested (seasonally, annually, or as otherwisespecified) by NERC, system data, including past, existing, and future facility andbulk electric system data, reports, and system performance information, necessaryto assess reliability and compliance with the NERC Planning Standards and therespective Regional planning criteria.

The facility and bulk electric system data, reports, and system performanceinformation shall include, but not be limited to, one or more of the followingtypes of information as outlined below:

1. Electric Demand and Net Energy for Load (actual and projected demandsand net energy for load, forecast methodologies, forecast assumptions anduncertainties, and treatment of demand-side management)

2. Resource Adequacy and Supporting Information (Regional assessmentreports, existing and planned resource data, resource availability andcharacteristics, and fuel types and requirements)

NERC/WECC Planning StandardsI. System Adequacy and Security B. Reliability Assessment

NERC/WECC Planning Standards 28

3. Demand-Side Resources and Their Characteristics (program ratings, effectson annual system loads and load shapes, contractual arrangements, andprogram durations)

4. Supply-Side Resources and Their Characteristics (existing and plannedgenerator units, ratings, performance characteristics, fuel types andavailability, and real and reactive capabilities)

5. Transmission System and Supporting Information (thermal, voltage, andstability limits, contingency analyses, system restoration, system modelingand data requirements, and protection systems)

6. System Operations and Supporting Information (extreme weather impacts,interchange transactions, and congestion impacts on the reliability of theinterconnected bulk electric systems)

7. Environmental and Regulatory Issues and Impacts (air and water qualityissues, and impacts of existing, new, and proposed regulations andlegislation)

NERC/WECC Planning StandardsI. System Adequacy and Security C. Facility Connection Requirements

NERC/WECC Planning Standards 29

Introduction

All facilities involved in the generation, transmission, and use of electricity must be properlyconnected to the bulk interconnected transmission systems (generally 100 kV and higher) to avoiddegrading the reliability of the electric systems to which they are connected.

To avoid adverse impacts on reliability when making connections to the interconnected bulkelectric systems, generation and transmission owners and electricity end-users must meet facilityconnection and performance requirements as specified by those responsible for the reliability ofthe bulk interconnected transmission systems.

Standards

S1. Facility connection requirements shall be documented, maintained, and published byvoltage class, capacity, and other characteristics that are applicable to generation,transmission, and electricity end-user facilities which are connected to, or beingplanned to be connected to, the bulk interconnected transmission systems.

S2. Generation, transmission, and electricity end-user facilities, and their modifications,shall be planned and integrated into the interconnected transmission systems incompliance with NERC Planning Standards, applicable Regional, subregional, powerpool, and individual system planning criteria and facility connection requirements.

Measurements

M1. Transmission providers, in conjunction with transmission owners, shall document,maintain, and publish facility connection requirements for

a. generation facilities,b. transmission facilities, andc. end-user facilities

to ensure compliance with NERC Planning Standards and applicable Regional,subregional, power pool, and individual transmission provider/owner planningcriteria and facility connection requirements.

Facility connection requirements shall address, but are not limited to, thefollowing items:

1. Procedures for coordinated joint studies of new facilities and their impactson the interconnected transmission systems.

NERC/WECC Planning StandardsI. System Adequacy and Security C. Facility Connection Requirements

NERC/WECC Planning Standards 30

2. Procedures for notification of new or modified facilities to others (thoseresponsible for the reliability of the interconnected transmission systems) assoon as feasible.

3. Voltage level and MW and Mvar capacity or demand at point of connection.4. Breaker duty and surge protection.5. System protection and coordination.6. Metering and telecommunications.7. Grounding and safety issues.8. Insulation and insulation coordination.9. Voltage, reactive power, and power factor control.10. Power quality impacts.11. Equipment ratings.12. Synchronizing of facilities.13. Maintenance coordination.14. Operational issues (abnormal frequency and voltages).15. Inspection requirements for existing or new facilities.16. Communications and procedures during normal and emergency operating

conditions.

Facility connection requirements shall be maintained and updated as required.

Documentation of these requirements shall be available to the users of thetransmission systems, the Regions, and NERC on request (five business days).(S1)

M2. Those entities responsible for the reliability of the interconnected transmissionsystems and those entities seeking to integrate generation facilities, transmissionfacilities, and electricity end-user facilities shall coordinate and cooperate on theirrespective assessments to evaluate the reliability impact of the new facilities andtheir connections on the interconnected transmission systems and to ensurecompliance with NERC Planning Standards and applicable Regional,subregional, power pool, and individual system planning criteria and facilityconnection requirements.

The entities involved shall present evidence that they have cooperated on theassessment of the reliability impacts of new facilities on the interconnectedtransmission systems. While these studies may be performed independently, theresults shall be jointly evaluated and coordinated by the entities involved.Assessments shall include steady-state, short-circuit, and dynamics studies asnecessary to evaluate system performance under Standard I.A.

Documentation of these assessments shall include study assumptions, systemperformance, alternatives considered, and jointly coordinated recommendations.

NERC/WECC Planning StandardsI. System Adequacy and Security C. Facility Connection Requirements

NERC/WECC Planning Standards 31

This documentation shall be retained for three years and shall be provided to theRegions and NERC on request (within 30 days). (S2)

Guides

G1. Inspection requirements for connected facilities or new facilities to be connectedshould be included in the facility connection requirements documentation.

G2. Notification of new facilities to be connected, or modifications of existing facilitiesalready connected to the interconnected transmission systems should be provided tothose responsible for the reliability of the interconnected transmission systems assoon as feasible to ensure that a review of the reliability impact of the facilities andtheir connections can be performed and that the facilities are placed in service in atimely manner.

G3. Use of common data and modeling techniques is encouraged.

NERC/WECC Planning StandardsI. System Adequacy and Security D. Voltage Support

and Reactive Power

NERC/WECC Planning Standards 32

Introduction

Sufficient reactive resources must be located throughout the electric systems, with a balancebetween static and dynamic characteristics. Both static and dynamic reactive power resources areneeded to supply the reactive power requirements of customer demands and the reactive powerlosses in the transmission and distribution systems, and provide adequate system voltage supportand control. They are also necessary to avoid voltage instability and widespread system collapsein the event of certain contingencies. Transmission systems cannot perform their intendedfunctions without an adequate reactive power supply.

Dynamic reactive power support and voltage control are essential during power systemdisturbances. Synchronous generators, synchronous condensers, and static var compensators(SVCs and STATCOMs) can provide dynamic support. Transmission line charging and seriesand shunt capacitors are also sources of reactive support, but are static sources.

Reactive power sources must be distributed throughout the electric systems among thegeneration, transmission, and distribution facilities, as well as at some customer locations.Because customer reactive demands and facility loadings are constantly changing, coordinationof distribution and transmission reactive power is required. Unlike active or real power (MWs),reactive power (Mvars) cannot be transmitted over long distances and must be supplied locally.

Standard

S1. Reactive power resources, with a balance between static and dynamic characteristics,shall be planned and distributed throughout the interconnected transmission systemsto ensure system performance as defined in Categories A, B, and C of Table I in theI.A. Standards on Transmission Systems.

WECC-S1 For transfer paths, post-transient voltage stability is required with the pathmodeled at a minimum of 105% of the path rating (or Operational TransferCapability) for system normal conditions (Category A) and for singlecontingencies (Category B). For multiple contingencies (Category C), post-transient voltage stability is required with the path modeled at a minimum of102.5% of the path rating (or Operational Transfer Capability).

WECC-S2 For load areas, post-transient voltage stability is required for the area modeledat a minimum of 105% of the reference load level for system normal conditions(Category A) and for single contingencies (Category B). For multiplecontingencies (Category C), post-transient voltage stability is required with thearea modeled at a minimum of 102.5% of the reference load level. For thisstandard, the reference load level is the maximum established planned loadlimit for the area under study.

NERC/WECC Planning StandardsI. System Adequacy and Security D. Voltage Support

and Reactive Power

NERC/WECC Planning Standards 33

WECC-S3 Specific requirements that exceed the minimums specified in I.D WECC-S1 andS2 may be established, to be adhered to by others, provided that technicaljustification has been approved by the Planning Coordination Committee of theWECC.

WECC-S4 These Standards apply to internal WECC Member Systems as well as betweenWECC Member Systems.

Measurements

M1. Entities responsible for the reliability of the interconnected transmission systemsshall conduct assessments (at least every five years or as required by changes insystem conditions) to ensure reactive power resources are available to meetprojected customer demands, firm (non-recallable) electric power transfers, andthe system performance requirements as defined in Categories A, B, and C ofTable I of the I.A. Standards on Transmission Systems. Documentation of theseassessments shall be provided to the Regions and NERC on request. (S1)

M2. Generation owners and transmission providers shall work jointly to optimize theuse of generator reactive power capability. These joint efforts shall include:

a. Coordination of generator step-up transformer impedance and tapspecifications and settings,

b. Calculation of underexcited limits based on machine thermal and stabilityconsiderations, and

c. Ensuring that the full range of generator reactive power capability isavailable for applicable normal and emergency network voltage ranges.(S1)

Guides

G1. Transmission owners should plan and design their reactive power facilities so asto ensure adequate reactive power reserves in the form of dynamic reserves atsynchronous generators, synchronous condensers, and static var compensators(SVCs and STATCOMs) in anticipation of system disturbances. For example,fixed and mechanically-switched shunt compensation should be used to the extentpractical so as to ensure reactive power dynamic reserves at generators and SVCsto minimize the impact of system disturbances.

G2. Distribution entities and customers connected directly to the transmission systemsshould plan and design their systems to operate at close to unity power factor tominimize the reactive power burden on the transmission systems.

NERC/WECC Planning StandardsI. System Adequacy and Security D. Voltage Support

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NERC/WECC Planning Standards 34

G3. At continuous rated power output, new synchronous generators should have anoverexcited power factor capability, measured at the generator terminals, of 0.9 orless and an underexcited power factor capability of 0.95 or less.

If a synchronous generator does not meet this requirement, the generation ownershould make alternate arrangements for supplying an equivalent dynamic reactivepower capability to meet the area’s reactive power requirements.

G4. Reactive power compensation should be close to the area of high reactive powerconsumption or production.

G5. A balance between fixed compensation, mechanically-switched compensation,and continuously-controlled equipment should be planned.

G6. Voltage support and voltage collapse studies should conform to Regionalguidelines.

G7. Power flow simulation of contingencies, including P-V and V-Q curve analyses,should be used and verified by dynamic simulation when steady-state analysesindicate possible insufficient voltage stability margins.

G8. Consideration should be given to generator shaft clutches or hydro waterdepression capability to allow generators to operate as synchronous condensers.

WECC-G1 Each system should plan and provide, by ownership or agreement, sufficientreactive power capacity and voltage control facilities to satisfy the requirementsof its own system

WECC-G2 Reactive Power Margin Requirements: The development of “Reactive PowerMargin Requirements” based on the V-Q methodology developed by TSS (e.g.,400 MVAR at a particular bus) provides one alternate way to screen cases anddetermine whether or not they likely meet this criteria. The “Reactive PowerMargin Requirement” is a proxy for Standards I.D WECC-S1 throughWECC-S3.

WECC-G3 Identification of Critical Conditions: It may be necessary to study a variety ofload, transfer, and generation patterns to identify the most critical set of systemconditions. For example, various conditions should be considered, such as:peak load conditions with maximum imports, low load conditions withminimum generation, and maximum interface flow conditions with worst caseload conditions.

WECC-G4 When developing the 105% and 102.5% load or transfer cases to demonstrateconformance with I.D WECC-S1, S2, and S3, conformance with the

NERC/WECC Planning StandardsI. System Adequacy and Security D. Voltage Support

and Reactive Power

NERC/WECC Planning Standards 35

performance requirement (e.g., facility thermal loading limits) identified inSection I.A is not required.

WECC-G5 Load Voltage Response Assumption: Loads and distribution regulating devicesin the study area should be modeled as detailed as is practical. If detailed loadmodels cannot be estimated, the loads can be represented as constant MVA inlong-term (post transient) voltage stability study; this representationapproximates the effect of voltage regulation by LTC bulk power deliverytransformers and distribution voltage regulators. For short-term (transient)voltage stability and dynamic simulation, dynamic modeling of inductionmotors is recommended.

WECC-G6 Load Shedding: Controlled load interruption, as allowed in Table I of theNERC/WECC Planning Standards, is allowed to meet these standards.

WECC-G7 Automatic Switching: Planned operation of automatic switching (distributionvoltage regulators, switched static devices, etc.) may be modeled to meet thesestandards.

WECC-G8 Voltage magnitudes alone are poor indicators of voltage stability or securitybecause the system may be near collapse even if voltages are near normaldepending on the system characteristics. The system should be planned so thatthere is sufficient margin between normal operating point and the collapsepoint to allow for reliable system operation.

WECC-G9 In assessing the requirements under WECC-S3, relevant system variations anduncertainties should be considered. Types of analysis that may be used includeP-V, V-Q, and dynamic studies.

WECC-G10 Voltage stability analysis and the evaluation of balance between dynamic andstatic reactive power resources may be performed using the methodologiesadopted by TSS.

NERC/WECC Planning StandardsI. System Adequacy and Security E. Transfer Capability

1. Total and Available Transfer Capabilities

NERC/WECC Planning Standards 36

Introduction — Total and Available Transfer Capabilities

A competitive electricity market is dependent on the availability of transmission services. Theavailability of these services must be based on the physical and electrical characteristics andcapabilities of the interconnected transmission networks as reliably planned and operated underthe NERC Planning Standards, the NERC Operating Policies, and applicable Regional,subregional, power pool, and individual system criteria.

The total transfer capability (TTC) and the available transfer capability (ATC) for particulardirections must be available to the market participants. These transfer capabilities are generallycalculated through computer simulations of the interconnected transmission systems under aspecific set of system conditions.

TTC and ATC values must balance both technical and commercial issues. The definitions of thekey TTC and ATC transfer capability terms that bridge the technical characteristics ofinterconnected transmission system performance and the commercial requirements associatedwith transmission service requests are as follows:

• The total transfer capability (TTC) is the amount of electric power that can be movedor transferred reliably from one area to another area of the interconnected transmissionsystems by way of all transmission lines (or paths) between those areas under specifiedsystem conditions.

• Available transfer capability (ATC) is a measure of the transfer capability remaining inthe physical transmission network for further commercial activity over and abovealready committed uses. It is defined as TTC less existing transmission commitments(including retail customer service), less a capacity benefit margin (CBM)), less atransmission reliability margin (TRM). (The transfer capability margins - CBM andTRM - are defined under section I.E.2 of the Planning Standards document.)

ATC is expressed as:

ATC = TTC – Existing Transmission Commitments (includes retail customerservice) – CBM – TRM

Depending on the methodology used, either ATC or TTC may be calculated first.

TTC and ATC values are projected values. They are intended to indicate the available transfercapabilities of the interconnected transmission network.

Standards

S1. Each Region shall develop a methodology for calculating Total Transfer Capability(TTC) and Available Transfer Capability (ATC) that shall comply with the above

NERC/WECC Planning StandardsI. System Adequacy and Security E. Transfer Capability

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NERC definitions for TTC and ATC, the NERC Planning Standards, andapplicable Regional criteria.

Each Regional TTC and ATC methodology and the resulting TTC and ATC valuesshall be available to transmission users in the electricity market.

Measurements

M1. Each Region, in conjunction with its members, shall develop and document aRegional TTC and ATC methodology. Certain systems that are not required topost ATC values are exempt from this Standard.

This Regional methodology shall be available to NERC, the Regions, and thetransmission users in the electricity market. (S1)

Each Region’s TTC and ATC methodology shall (S1):

a. Include a narrative explaining how TTC and ATC values aredetermined.

b. Account for how the reservations and schedules for firm (non-recallable)and non-firm (recallable) transfers, both within and outside thetransmission provider’s system, are included.

c. Account for the ultimate points of power injection (sources) and powerextraction (sinks) in TTC and ATC calculations.

d. Describe how incomplete or so-called partial path transmissionreservations are addressed. (Incomplete or partial path transmissionreservations are those for which all transmission reservations necessaryto complete the transmission path from ultimate source to ultimate sinkare not identifiable due to differing reservation priorities, durations, orthat the reservations have not all been made.)

e. Require that TTC and ATC values and postings within the current weekbe determined at least once per day, that daily TTC and ATC values andpostings for day 8 through the first month be determined at least onceper week, and that monthly TTC and ATC values and postings formonths 2 through 13 be determined at least once per month.

f. Indicate the treatment and level of customer demands, includinginterruptible demands.

g. Specify how system conditions, limiting facilities, contingencies,transmission reservations, energy schedules, and other data needed bytransmission providers for the calculation of TTC and ATC values areshared and used within the Region and with neighboring interconnectedelectric systems, including adjacent systems, subregions, and Regions.In addition, specify how this information is to be used to determine TTCand ATC values. If some data is not used, provide an explanation.

NERC/WECC Planning StandardsI. System Adequacy and Security E. Transfer Capability

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NERC/WECC Planning Standards 38

h. Describe how the assumptions for and the calculations of TTC and ATCvalues change over different time (such as hourly, daily, and monthly)horizons.

i. Describe the Region’s practice on the netting of transmissionreservations for purposes of TTC and ATC determination.

Each Regional TTC and ATC methodology shall address each of the items listedabove and shall explain its use in determining TTC and ATC values.

The most recent version of the documentation of each Region’s TTC and ATCmethodology shall be available on a web site accessible by NERC, the Regions,and the transmission users in the electricity market.

M2. Eliminated. Requirements included in Measurement M3.

M3. Each Region, in conjunction with its members, shall develop and implement aprocedure to review periodically (at least annually) and ensure that the TTC andATC calculations and resulting values of member transmission providers complywith the Regional TTC and ATC methodology, the NERC Planning Standards,and applicable Regional criteria. Documentation of the results of the most currentRegional reviews shall be provided to NERC on request (within 30 days). (S1)

M4. Each Region, in conjunction with its members, shall develop and document aprocedure on how transmission users can input their concerns or questionsregarding the TTC and ATC methodology and values of the transmissionprovider(s), and how these concerns or questions will be addressed.Documentation of the procedure shall be available on a web site accessible by theRegions, NERC, and the transmission users in the electricity market. (S1

Each Region’s procedure shall specify (S1):

a. The name, telephone number, and email address of a contact person towhom concerns are to be addressed.

b. The amount of time it will take for a response.c. The manner in which the response will be communicated (e.g., email,

letter, telephone, etc.).d. What recourse a customer has if the response is deemed unsatisfactory.

Guides

G1. The Regional responses to transmission user concerns or questions regarding theATC and TTC methodology and values of the transmission provider(s) should bemade publicly available, possibly on a web site, for consistency and to avoidduplicative customer questions.

NERC/WECC Planning StandardsI. System Adequacy and Security E. Transfer Capablity

2. Transfer Capability Margins

NERC/WECC Planning Standards 39

Introduction — Transfer Capability Margins

In defining the components that comprise Available Transfer Capability (ATC), twotransmission transfer capability margin terms, known as Capacity Benefit Margin (CBM) andTransmission Reliability Margin (TRM), are introduced.

The definitions for CBM and TRM are:

• Capacity Benefit Margin (CBM) is the amount of firm transmissiontransfer capability preserved by the transmission provider for load-serving entities (LSEs), whose loads are located on that transmissionprovider’s system, to enable access by the LSEs to generation frominterconnected systems to meet generation reliability requirements.Preservation of CBM for an LSE allows that entity to reduce its installedgenerating capacity below that which may otherwise have beennecessary without interconnections to meet its generation reliabilityrequirements. The transmission transfer capability preserved as CBM isintended to be used by the LSE only in times of emergency generationdeficiencies.

• Transmission Reliability Margin (TRM) is the amount of transmissiontransfer capability necessary to provide reasonable assurance that theinterconnected transmission network will be secure. TRM accounts forthe inherent uncertainty in system conditions and the need for operatingflexibility to ensure reliable system operation as system conditionschange.

The methodologies used to determine CBM and TRM and the resulting CBM and TRM valuesimpact ATC and, therefore, must be available to the market participants.

NERC/WECC Planning StandardsI. System Adequacy and Security E. Transfer Capablity

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NERC/WECC Planning Standards 40

Standards

S1 Each Region shall develop a methodology for calculating Capacity BenefitMargin (CBM) that shall comply with the above NERC definition for CBMand applicable Regional criteria.

Each Regional CBM methodology and the resulting CBM values shall beavailable to transmission users in the electricity market.

S2. Each Region shall develop a methodology for calculating TransmissionReliability Margin (TRM) that shall comply with the above NERC definitionfor TRM and applicable Regional criteria.

Each Regional TRM methodology and the resulting TRM values shall beavailable to transmission users in the electricity market.

Measurements

M1. Each Region, in conjunction with its members, shall develop and document aRegional CBM methodology. This Regional methodology shall be available toNERC, the Regions, and the transmission users in the electricity market. (S1)

Each Region’s CBM methodology shall (S1):

a. Specify that the method used by each Regional member to determine itsgeneration reliability requirements as the basis for CBM shall beconsistent with its generation planning criteria.

b. Specify the frequency of calculation of the generation reliabilityrequirement and associated CBM values.

c. Require that generation unit outages considered in a transmissionprovider’s CBM calculation be restricted to those units within thetransmission provider’s system.

d. Require that CBM be preserved only on the transmission provider’ssystem where the load serving entity’s load is located (i.e., CBM is animport quantity only).

e. Describe the inclusion or exclusion rationale for generation resources ofeach LSE including those generation resources not directly connected tothe transmission provider’s system but serving LSE loads connected tothe transmission provider’s system.

f. Describe the inclusion or exclusion rationale for generation connected tothe transmission provider’s system but not obligated to servenative/network load connected to the transmission provider’s system.

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g. Describe the formal process and rationale for the Region to grant anyvariances to individual transmission providers from the Regional CBMmethodology.

h. Specify the relationship of CBM to the generation reliabilityrequirement and the allocation of the CBM values to the appropriatetransmission facilities. The sum of the CBM values allocated to allinterfaces shall not exceed that portion of the generation reliabilityrequirement that is to be provided by outside resources.

i. Describe the inclusion or exclusion rationale for the loads of each LSE,including interruptible demands and buy-through contracts (type ofservice contract that offers the customer the option to be interrupted orto accept a higher rate for service under certain conditions).

j. Describe the inclusion or exclusion rationale for generation reservesharing arrangements in the CBM values.

Each Regional CBM methodology shall address each of the items listed aboveand shall explain its use, if any, in determining CBM values. Other items that areRegional specific or that are considered in each respective Regional methodologyshall also be explained along with their use in determining CBM values.

The most recent version of the documentation of each Region’s CBMmethodology shall be available on a web site accessible by NERC, the Regions,and the transmission users in the electricity market.

M2. Eliminated. Requirements included in Measurement M3.

M3. Each Region, in conjunction with its members, shall develop and implement aprocedure to review the CBM calculations and values of member transmissionproviders to ensure that they comply with the Regional CBM methodology andare periodically updated (at least annually) and available to transmission users.Documentation of the results of the most current Regional reviews shall beprovided to NERC on request (within 30 days). (S1)

This Regional procedure shall:

a. Indicate the frequency under which the verification review shall beimplemented.

b. Require review of the process by which CBM values are updated, andtheir frequency of update, to ensure that the most current CBM valuesare available to transmission users.

c. Require review of the consistency of the transmission provider’s CBMcomponents with its published planning criteria. A CBM value isconsidered consistent with published planning criteria if the samecomponents that comprise CBM are also addressed in the planning

NERC/WECC Planning StandardsI. System Adequacy and Security E. Transfer Capablity

2. Transfer Capability Margins

NERC/WECC Planning Standards 42

criteria. The methodology used to determine and apply CBM does nothave to involve the same mechanics as the planning process, but thesame uncertainties must be considered and any simplifying assumptionsexplained. It is recognized that ATC determinations are often timeconstrained and thus will not permit the use of the same mechanicsemployed in the more rigorous planning process.

d. Require CBM values to be periodically updated (at least annually) andavailable to the Regions, NERC, and transmission users in the electricitymarkets.

The documentation of the Regional CBM procedure shall be available to NERCon request (within 30 days). Documentation of the results of the most currentimplementation of the procedure shall be available to NERC on request (within30 days).

M4. Each transmission provider shall document and make available its procedures onthe use of CBM (scheduling of electrical energy against a CBM preservation) tothe Regions, NERC, and the transmission users in the electricity market.

These procedures shall:

a. Require that CBM is to be used only after the following steps have beentaken (as time permits): all non-firm sales have been terminated, direct-control load management has been implemented, and customerinterruptible demands have been interrupted. CBM may be used toreestablish operating reserves.

b. Require that CBM shall only be used if the LSE calling for its use isexperiencing a generation deficiency and its transmission provider isalso experiencing transmission constraints relative to imports of energyon its transmission system.

c. Describe the conditions under which CBM may be available as non-firmtransmission service. (S1)

The transmission providers shall make their CBM use procedures available on aweb site accessible by the Regions, NERC, and the transmission users in theelectricity market.

M5. Each transmission provider that uses CBM shall report to the Regions, NERC,and the transmission users the use of CBM by the load-serving entities’ loads onits system, except for CBM sales as non-firm transmission service. Thisdisclosure may be after the fact. (S1)

Within 15 days after the use of CBM for emergency purposes, a transmissionprovider shall make available the 1) circ*mstances, 2) duration, and 3) amount of

NERC/WECC Planning StandardsI. System Adequacy and Security E. Transfer Capablity

2. Transfer Capability Margins

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CBM used. This information shall be available on a web site accessible by theRegions, NERC, and the transmission users in the electricity market.

The use of CBM also shall be consistent with the transmission provider’s CBMuse procedures.

The scheduling of energy against a CBM preservation as non-firm transmissionservice need not be disclosed to comply with this Standard.

M6. Each Region, in conjunction with its members, shall develop and document aRegional TRM methodology. This Regional methodology shall be available toNERC, the Regions, and the transmission users in the electricity market. (S2)

Each Region’s TRM methodology shall (S2):

a. Specify the update frequency of TRM calculations.b. Specify how TRM values are incorporated into ATC calculations.c. Specify the uncertainties accounted for in TRM and the methods used to

determine their impacts on the TRM values.

The following components of uncertainty, if applied, shall be accountedfor solely in TRM and not CBM: aggregate load forecast error (notincluded in determining generation reliability requirements), loaddistribution error, variations in facility loadings due to balancing ofgeneration within a control area, forecast uncertainty in transmissionsystem topology, allowances for parallel path (loop flow) impacts,allowances for simultaneous path interactions, variations in generationdispatch, and short-term operator response (operating reserve actions notexceeding a 59-minute window).

Any additional components of uncertainty shall benefit theinterconnected transmission systems, as a whole, before they shall bepermitted to be included in TRM calculations.

d. Describe the conditions, if any, under which TRM may be available tothe market as non-firm transmission service.

e. Describe the formal process for the Region to grant any variances toindividual transmission providers from the Regional TRM methodology.

Each Regional TRM methodology shall address each of the items above and shallexplain its use, if any, in determining TRM values. Other items that are Regionalspecific or that are considered in each respective Regional methodology shall alsobe explained along with their use in determining TRM values.

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2. Transfer Capability Margins

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The most recent version of the documentation of each Region’s methodologyshall be available on a web site accessible by NERC, the Regions, and thetransmission users in the electricity market.

M7. Eliminated. Requirements included in Measurement M8.

M8. Each Region, in conjunction with its members, shall develop and implement aprocedure to review the TRM calculations and values of member transmissionproviders to ensure that they comply with the Regional TRM methodology andare periodically updated and available to transmission users. Documentation ofthe results of the most current Regional reviews shall be provided to NERC onrequest (within 30 days). (S2)

This Regional procedure shall:

a. Indicate the frequency under which the verification review shall beimplemented.

b. Require review of the process by which TRM values are updated, andtheir frequency of update, to ensure that the most current TRM valuesare available to transmission users.

c. Require review of the consistency of the transmission provider’s TRMcomponents with its published planning criteria. A TRM value isconsidered consistent with published planning criteria if the samecomponents that comprise TRM are also addressed in the planningcriteria. The methodology used to determine and apply TRM does nothave to involve the same mechanics as the planning process, but thesame uncertainties must be considered and any simplifying assumptionexplained. It is recognized that ATC determinations are often timeconstrained and thus will not permit the use of the same mechanicsemployed in the more rigorous planning process.

d. Require TRM values to be periodically updated (at least prior to eachseason ⎯ winter, spring, summer, and fall), as necessary, and madeavailable to the Regions, NERC, and transmission users in the electricitymarket.

The documentation of the Regional TRM procedure shall be available to NERCon request (within 30 days). Documentation of the results of the most currentimplementation of the procedure shall be available to NERC on request (within30 days).

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Introduction

Recorded information about transmission system faults or disturbances is essential to determinethe performance of system components and to analyze the nature and cause of a disturbance.Such information can help to identify equipment misoperations, and the causes of oscillationsthat may have contributed to a disturbance. Protection system and control deficiencies can alsobe analyzed and corrected, reducing the risk of recurring misoperations. Transient modelingdata can be gathered from fault and sequence-of-event monitoring equipment and long-timemodeling data can be gathered from dynamic monitoring equipment using wide-areameasurement techniques or swing sensors.

Standards

S1. Requirements shall be established on a Regional basis for the installation ofdisturbance monitoring equipment (e.g., sequence-of-event, fault recording, anddynamic disturbance recording equipment) that is necessary to ensure data isavailable to determine system performance and the causes of system disturbances.

S2. Requirements for providing disturbance monitoring data for the purpose ofdeveloping, maintaining, and updating transmission system models shall beestablished on a Regional basis.

Measurements

M1. Each Region shall develop comprehensive requirements for the installation ofdisturbance monitoring equipment to ensure data is available to determine systemperformance and the causes of system disturbances.

The comprehensive Regional requirements shall include the following items:

Technical requirements:

1. Type of data recording capability (e.g., sequence-of-event, fault recording,dynamic disturbance recording)

2. Equipment characteristics (e.g., recording duration requirements, timesynchronization requirements, data format requirements, event triggeringrequirements)

3. Monitoring, recording, and reporting capabilities of the equipment (e.g.,voltage, current, MW, Mvar, frequency)

4. Data retention capabilities (e.g., length of time data is to be available forretrieval)

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Criteria for the location of monitoring equipment:5. Regional coverage requirements (e.g., by voltage, geographic area, electric

area/subarea)6. Installation requirements (e.g., substations, transmission lines, generators)

Testing and maintenance requirements:7. Responsibility for maintenance and/or testing

Documentation requirements:8. Requirements for periodic updating, review, and approval of the Regional

requirements

The Regional requirements shall be provided to other Regions and NERC onrequest (five business days).

M2. Regional members shall provide to their respective Regions a list of theirdisturbance monitoring equipment that is installed and operational in compliancewith Regional requirements. (S1)

M3. Each generation owner and transmission provider shall maintain a database of alldisturbance monitoring equipment installations, and shall provide suchinformation to the Region and NERC on request. (S1)

M4. Each Region shall establish requirements for providing disturbance monitoringdata to ensure that data is available to determine system performance and thecauses of system disturbances. Documentation of Regional data reportingrequirements shall be provided to appropriate Regions and NERC on request.(S2)

M5. Regional members shall provide to their respective Regions system fault anddisturbance data in compliance with Regional requirements. Each Region shallmaintain and annually update a database of the recorded information. (S1, S2)

M6. Regional members shall use recorded data from disturbance monitoringequipment to develop, maintain, and enhance steady-state and dynamic systemmodels and generator performance models. (S2)

Guides

G1. Data from transmission system disturbance monitoring equipment should be in aconsistent, time synchronized format.

G2. The Regional database should be used to identify locations on the transmissionsystems where additional disturbance monitoring equipment may be needed.

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G3. The monitored data from disturbance monitoring equipment should be used todevelop, maintain, validate, and enhance generator performance models andsteady-state and dynamic system models.

G4. Each Region should establish and coordinate the requirements for the installationof disturbance monitoring equipment with neighboring Regions.

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NERC/WECC Planning Standards 48

System modeling is the first step toward reliable interconnected transmission systems. Thetimely development of system modeling data to realistically simulate the electrical behavior ofthe components in the interconnected networks is the only means to accurately plan forreliability. To achieve this purpose, the NERC Planning Standards on System Modeling DataRequirements (II) establishes a set of common objectives for the development and submission ofnecessary data for electric system reliability assessment.

The detail in which the various system components are modeled should be adequate for all intra-and interregional reliability assessment activities. This means that system modeling data shouldinclude sufficient detail to ensure that system contingency, steady-state, and dynamic analysescan be simulated. Furthermore, any qualified user should be able to recognize significantlimiting conditions in any portion of the interconnected transmission systems.

The NERC Planning Standards, Measurements, and Guides pertaining to System ModelingData Requirements (II) are provided in the following sections:

A. System DataB. Generation EquipmentC. Facility RatingsD. Actual and Forecast DemandsE. Demand Characteristics (Dynamic)

These Standards, Measurements, and Guides shall apply to all system modeling necessary toachieve interconnected transmission system performance as described in the Standards onSystem Adequacy and Security (I) in this report.

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Introduction

Complete, accurate, and timely data is needed for system analyses to ensure the adequacy andsecurity of the interconnected transmission systems, meet projected customer demands, anddetermine the need for system enhancements or reinforcements.

System analyses include steady-state and dynamic (all time frames) simulations of the electricalnetworks. Data requirements for such simulated modeling include information on systemcomponents, system configuration, customer demands, and electric power transactions.

Standard

S1. Electric system data required for the analysis of the reliability of the interconnectedtransmission systems shall be developed and maintained.

Measurements

M1. All the users of the interconnected transmission systems shall provide appropriateequipment characteristics, system data, and existing and future interchangetransactions in compliance with the respective Interconnection-wide Regionaldata requirements and reporting procedures as defined in Standard II.A.S1, M2for the modeling and simulation of the steady-state behavior of the NERCInterconnections: Eastern, Western, and ERCOT.

This data shall be provided to the Regions, NERC, and those entities responsiblefor the reliability of the interconnected transmission systems as specified withinthe applicable reporting procedures (Standard II.A.S1, M2). If no schedule exists,then data shall be provided on request (30 business days).

M2. The Regions, in coordination with the entities responsible for the reliability of theinterconnected transmission systems, shall develop comprehensive steady-statedata requirements and reporting procedures needed to model and analyze thesteady-state conditions for each of the NERC Interconnections: Eastern, Western,and ERCOT. Within an Interconnection, the Regions shall jointly coordinate onthe development of the data requirements and reporting procedures for thatInterconnection.

The following list describes the steady-state data that shall be addressed in theInterconnection-wide requirements:

1. Bus (substation and switching station): name, nominal voltage, electricaldemand (load) supplied (consistent with the aggregated and dispersedsubstation demand data supplied per Standard II.D.), and location.

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2. Generating Units (including synchronous condensers, pumped storage, etc.):location, minimum and maximum ratings (net real and reactive power),regulated bus and voltage set point, and equipment status.

3. AC Transmission Line or Circuit (overhead and underground): nominalvoltage, impedance, line charging, normal and emergency ratings(consistent with methodologies defined and ratings supplied per StandardII.C.), equipment status, and metering locations.

4. DC Transmission Line (overhead and underground): Line parameters,normal and emergency ratings, control parameters, rectifier data, andinverter data.

5. Transformer (voltage and phase-shifting): nominal voltages of windings,impedance, tap ratios (voltage and/or phase angle or tap step size), regulatedbus and voltage set point, normal and emergency ratings (consistent withmethodologies defined and ratings supplied per Standard II.C.), andequipment status.

6. Reactive Compensation (shunt and series capacitors and reactors): nominalratings, impedance, percent compensation, connection point, and controllerdevice.

7. Interchange Transactions: Existing and future interchange transactionsand/or assumptions.

The data requirements and reporting procedures for each of the NERCInterconnections (Eastern, Western, and ERCOT) shall be documented, reviewed(at least every five years), and available to the Regions, NERC, and all users ofthe interconnected transmission systems on request (five business days).

M3. All users of the interconnected transmission systems shall provide appropriateequipment characteristics and system data in compliance with the respectiveInterconnection-wide Regional data requirements and reporting procedures asdefined in Standard II.A.S1, M4 for the modeling and simulation of the dynamicsbehavior of the NERC Interconnections: Eastern, Western, and ERCOT.

This data shall be provided to the Regions, NERC, and those entities responsiblefor the reliability of the interconnected transmission systems as specified withinthe applicable reporting procedures (Standard II.A. S1, M4). If no schedule exists,then data shall be provided on request (30 business days).

M4. The Regions, in coordination with the entities responsible for the reliability of theinterconnected transmission systems, shall develop comprehensive dynamics datarequirements and reporting procedures needed to model and analyze the dynamicbehavior or response of each of the NERC Interconnections: Eastern, Western and

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ERCOT. Within an interconnection, the Regions shall jointly coordinate on thedevelopment of the data requirements and reporting procedures for thatInterconnection. The following list describes the dynamics data that shall beaddressed in the Interconnection-wide requirements:

1. Unit-specific dynamics data shall be reported for generators andsynchronous condensers (including, as appropriate to the model, items suchas inertia constant, damping coefficient, saturation parameters, and directand quadrature axes reactances and time constants), excitation systems,voltage regulators, turbine-governor systems, power system stabilizers, andother associated generation equipment.

However, estimated or typical manufacturer's dynamics data, based on unitsof similar design and characteristics, may be submitted when unit-specificdynamics data cannot be obtained. In no case shall other than unit-specificdata be reported for generator units installed after 1990.

The Interconnection-wide requirements shall specify unit size thresholds forpermitting: 1.) the use of non-detailed vs. detailed models, 2.) the netting ofsmall generating units with bus load, and 3.) the combining of multiplegenerating units at one plant.

2. Device specific dynamics data shall be reported for dynamic devices,including, among others, static var controls (SVC), high voltage directcurrent systems (HVDC), flexible AC transmission systems (FACTS), andstatic compensators (STATCOM).

3. Dynamics data representing electrical demand (load) characteristics as afunction of frequency and voltage.

4. Dynamics data shall be consistent with the reported steady-state (powerflow) data supplied per Standard II.A.S1, M1.

M5. Data requirements for the steady-state and dynamics modeling of other associatedtransmission and generation facilities are included under the following sections ofthe Standards:

• Voltage Support and Reactive Power (I.D.)• Disturbance Monitoring (I.F.)• Generation Equipment (II.B.)

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• Facility Ratings (II.C.)• System Protection and Control (III)• System Restoration (IV)

M6. Load-serving entities shall provide actual and forecast demands for theirrespective customers for steady-state and dynamics system modeling as specifiedin the respective steady-state and dynamics procedural manuals for theInterconnections and in compliance with the Actual and Forecast Demands (II.D.)and Demand Characteristics (Dynamic) (II.E.) Standards in this report. (S1)

Guides

G1. Any changes to interconnection tie line data should be agreed upon by allinvolved facility owners.

G2. The in-service date should be the year and season that a facility will be operableor placed in service.

G3. The out-of-service date should be the year and season that the facility will beretired or taken out of service.

G4. All data should be screened to detect inappropriate or inaccurate data.

G5. The reactive limits of generators should be periodically reviewed and field tested,as appropriate, to ensure that reported var limits are attainable. (See GenerationEquipment Standard II.B.)

G6. Generating station service load (SSL) and auxiliary load representations should beprovided to those entities responsible for the reliability of the interconnectedtransmission systems on request. The presence of SSL in a dynamic simulationwill alter the bus angles derived from solution. This change in angle can besignificant from the steady-state, dynamic, and voltage control perspectives,especially for large generating units.

G7. To accurately model system inertia, the netting of generation and customerdemand should be avoided. For smaller units, the netting of generation and loadis acceptable.

G8. Generating units equal to or greater than 50 MVA should generally beindividually modeled. To maintain sufficient detail in the model, larger unitsshould not be lumped together.

G9. Smaller generating units at a particular station may be lumped together andrepresented as one unit. The lumping of generating units at a station is acceptable

NERC/WECC Planning StandardsII. System Modeling Data Requirements A. System Data

NERC/WECC Planning Standards 53

where all units have the same electrical and control characteristics. Equivalentlumped units should generally not exceed 300 MVA.

G10. The dynamics data for each generating unit should be supplied on the machine’sown MVA and kV base.

G11. Data for generator step-up transformers that are modeled as part of the generatordata record should include effective tap ratios and per unit impedance (R and Xvalues) on the transformer’s MVA and kV base.

G12. Generator models should conform to IEEE Guide for Synchronous GeneratorModeling Practices in Stability Analysis (IEEE Std. 1110-1991), or successor,Table 1, model 2.1 (for wound rotor machines) or 2.2 (for round rotor machines).

G13. Models of excitation systems, voltage regulators, and power system stabilizersshould conform to IEEE Recommended Practice for Excitation System Models forPower System Stability Studies (IEEE Std. 421.5-1992), or successor, if a modelappropriate to the equipment is available. If no model having the requiredcharacteristics is available, a library model or a user-written model of comparabledetail with a block diagram may be supplied. "Computer Models forRepresentation of Digital-Based Excitation Systems", IEEE Working GroupReport, IEEE Transactions on Energy Conversion, Vol. 11., No. 3,September 1996, should be considered in developing models of digital-basedexcitation systems.

G14. Models of turbine-governor systems for steam units should conform to IEEECommittee Report, "Dynamic Models for Steam and Hydro Turbines", aspublished in IEEE Transactions on Power Apparatus and Systems,Nov./Dec 1973, model 1. If this model lacks the characteristics required torepresent the dynamic response of the turbine governor system within therequired frequency range and time interval, a library model or a user-writtenmodel of comparable detail with a block diagram may be supplied. "DynamicModels for Fossil Fueled Steam Units in Power System Studies", IEEE WorkingGroup Report, IEEE Transactions on Power Systems, Vol.6, No. 2, May 1991,should be considered in developing models of steam turbine governor systems.

G15. Models of turbine-governor systems for hydro units should conform to IEEECommittee Report, "Dynamic Models for Steam and Hydro Turbines", aspublished in IEEE Transactions on Power Apparatus and Systems,Nov./Dec. 1973, model 2. If this model lacks the characteristics required torepresent the dynamic response of the turbine governor system within therequired frequency range and time interval, a library model or a user-writtenmodel of comparable detail with a block diagram may be supplied. "HydraulicTurbine and Turbine Control Models for System Dynamic Studies", IEEEWorking Group Report, IEEE Transactions on Power Systems, Vol.7., No. 1,

NERC/WECC Planning StandardsII. System Modeling Data Requirements A. System Data

NERC/WECC Planning Standards 54

February 1992, should be considered in developing models of hydro turbinegovernor systems.

G16. Models of turbine-governor systems for combustion turbine units shouldrepresent appropriate gains, limits, time constants and damping, and shouldinclude a parameter explicitly setting the ambient temperature load limit if thislimits unit output for ambient temperatures expected during the season understudy. "Dynamic Models for Combined Cycle Plants in Power System Studies",IEEE Working Group Report, IEEE Transactions on Power Systems, Vol.9., No.3, August 1994, should be considered in developing models of combustion turbinegovernor systems.

NERC/WECC Planning StandardsII. System Modeling Data Requirements B. Generation Equipment

NERC/WECC Planning Standards 55

Introduction

Validation of generator modeling data through field verification and testing is critical to thereliability of the interconnected transmission systems. Accurate, validated generator models anddata are essential for planning and operating studies used to ensure electric system reliability.

Generating capability to meet projected system demands and provide the required amount ofgeneration capacity margins is necessary to ensure service reliability. This generating capabilitymust be accounted for in a uniform manner that ensures the use of realistically attainable valueswhen planning and operating the systems or scheduling equipment maintenance.

Synchronous generators are the primary means of voltage and frequency control in the bulkinterconnected electric systems. The correct operation of generator controls can be the crucialfactor in whether the electric systems can sustain a severe disturbance without a cascadingbreakup of the interconnected network. Generator dynamics data is used to evaluate the stabilityof the electric systems, analyze actual system disturbances, identify potential stability problems,and analytically validate solutions for the identified problems.

Generator reactive capability is commonly derived from the generator real and reactivecapability curves supplied by the manufacturer. Reactive power generation limits derived in thismanner can be optimistic as heating or auxiliary bus voltage limits may be encountered beforethe generator reaches its maximum sustained reactive power capability. Manufacturer-provideddesign data may also not accurately reflect the characteristics of operational field equipmentbecause settings can drift and components deteriorate over time. Field personnel may alsochange equipment settings (to resolve specific local problems) that may not be communicated tothose responsible for developing a system modeling database and conducting systemassessments. It is important to know the actual reactive power limits, control settings, andresponse times of generation equipment and to represent this information accurately in thesystem modeling data that is supplied to the Regions and those entities responsible for thereliability of the interconnected transmission systems.

Standard

S1. Generation equipment shall be tested to verify that data submitted for steady-state and dynamics modeling in planning and operating studies is consistentwith the actual physical characteristics of the equipment. The data to beverified and provided shall include generator gross and net dependablecapability, gross and net reactive power capability, voltage regulator controls,speed/load governor controls, and excitation systems.

Measurements

M1. Each Region shall establish and maintain procedures for generation equipmentdata verification and testing for all types of generating units in its Region. These

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procedures shall address generator gross and net dependable capability, reactivepower capability, voltage regulator controls, speed/load governor controls, andexcitation systems (including power system stabilizers and other devices, ifapplicable). These procedures shall also address generating unit exemptioncriteria and shall require documentation of those generating units that are exemptfrom a portion or all of these procedures. (S1)

M2. Generation equipment owners shall annually test to verify the gross and netdependable capability of their units. They shall provide the Regions with thefollowing information on request:

a. Summer and winter gross and net capabilities of each unit based on thepower factor level expected for each unit at the time of summer andwinter peak demand, respectively.

b. Active or real power requirements of auxiliary loads.

c. Date and conditions during tests (ambient and design temperatures,generator loadings, voltages, hydrogen pressure, high-side voltage, andauxiliary loads). (S1)

M3. Generation equipment owners shall test to verify the gross and net reactive powercapability of their units at least every five years. They shall provide the Regionswith the following information on request:

a. Maximum sustained reactive power capability (both lagging andleading) as a function of real power output and generator terminalvoltage. If safety or system conditions do not allow testing to fullcapability, computations and engineering reports of estimated capabilityshall be provided.

b. Reason for reactive power limitation.

c. Reactive power requirements of auxiliary loads.

d. Date and conditions during tests (ambient and design temperatures,generator loadings, voltages, hydrogen pressure, high-side voltage, andauxiliary loads). (S1)

M4. Generation equipment owners shall test voltage regulator controls and limitfunctions at least every five years. Upon request, they shall provide the Regionswith the status of voltage regulator testing as well as information that describeshow generator controls coordinate with the generator’s short-term capabilities andprotective relays. Test reports shall include minimum and maximum excitationlimiters (volts/hertz), gain and time constants, the type of voltage regulatorcontrol function, date tested, and the voltage regulator control setting. (S1)

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M5. Generation equipment owners shall test speed/load governor controls at leastevery five years. Upon request, they shall provide the Regions with the status ofgovernor tests as well as information that describes the characteristics (droop anddeadband) of the speed/load governing system. (S1)

M6. Generation equipment owners shall verify the dynamic model data for excitationsystems (including power system stabilizers and other devices, if applicable) atleast every five years. Design data for new or refurbished excitation systems shallbe provided at least one year prior to the in-service date with updated dataprovided once the unit is in service. Open circuit test response chart recordingsshall be provided showing generator field voltage and generator terminal voltage.(Brushless units shall include exciter field voltage and current.) (S1)

Guides

G1. The following guidelines should be observed during testing of the reactive powercapability of a generator:

a. The reactive power capability curve for each generating unit should beused to determine the expected reactive power capability.

b. Units should be tested while maintaining the scheduled voltage on thesystem bus. Coordination with other units may be necessary to maintainthe scheduled voltage.

c. Hydrogen pressure in the generating unit should be at rated operatingpressure.

d. Overexcited tests should be conducted for a minimum of two hours oruntil temperatures have stabilized.

e. When the maximum sustained reactive power output during the test isachieved, the following quantities should be recorded: generator grossMW and Mvar output, auxiliary load MW and Mvar, and generator andsystem voltage magnitudes.

G2. Most modern voltage regulators have limiting functions that act to bring thegenerating unit back within its capabilities when the unit experiences excessivefield voltage, volts per hertz, or underexcited reactive current. These limiters areoften intended to coordinate with other controls and protective relays. Testingshould be done that demonstrates correct action of the controls and confirms thedesired set points.

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G3. Generation equipment owners should make a best effort to verify data necessaryfor system dynamics studies. An “open circuit step in voltage” is an easy toperform test that can be used to validate the generating unit and excitation systemdynamics data. The open circuit test should be performed with the unit at ratedspeed and voltage but with its breakers open. Generator terminal voltage, fieldvoltage, and field current (exciter field voltage and current for brushlessexcitation systems) should be recorded with sufficient resolution such that thechange in voltages and current are clearly distinguishable.

G4. More detailed test procedures should be performed when there are significantdifferences between “open circuit step in voltage” tests and the step responsepredicted with the model data. Generator reactance and time constant data can bederived from standstill frequency response tests.

G5. The response of the speed/load governor controls should be evaluated for correctoperation whenever there is a system frequency deviation that is greater than thatestablished by the Regional procedures.

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Introduction

Knowledge of facility ratings is essential for the reliable planning and operation of the inter-connected transmission systems. Such ratings determine acceptable electrical loadings onequipment, before, during, and after system contingencies, and together with consideration ofnetwork voltage and system stability, determine the capability of the systems to deliver electricpower from generation to point of use.

Standard

S1. Electrical facilities used in the transmission, and storage of electricity shall be rated incompliance with applicable Regional, subregional, power pool, and individualtransmission provider/owner planning criteria.

Measurements

M1. Facility owners shall document the methodology (or methodologies) used todetermine their electrical facility ratings. Further, the methodology(ies) shall becompliant with applicable Regional, subregional, power pool, and individualtransmission provider/owner planning criteria.

The documentation shall include the methodology(ies) used to determinetransmission facility ratings for both normal and emergency conditions. It shallalso include methods for rating:

1. Transmission lines,2. Transformers,3. Series and shunt reactive elements,4. Terminal equipment (e.g., switches, breakers, current transformers, etc.),

and5. Electrical energy storage devices (e.g., superconducting magnetic energy

storage (SMES) system).

The rating of a transmission circuit shall not exceed the rating(s) of the mostlimiting element(s) in the circuit, including terminal connections and associatedequipment. In cases where protection systems and control settings constitute aloading limit on a facility, this limit shall become the rating for that facility.

Facility rating deviations from the methodology(ies), such as providing aconsistent basis for jointly-owned facilities and unique applications, shall bedocumented. Ratings of jointly-owned facilities shall be coordinated andprovided on a consistent basis.

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The documentation shall identify the assumptions used to determine each of thefacility ratings, including references to industry rating practices and standards(e.g., ANSI, IEEE, etc.). Seasonal ratings and variations in assumptions shall beincluded.

The documentation of the methodology(ies) used to determine transmissionfacility ratings shall be provided to the Regions and NERC on request (fivebusiness days).

M2. Facility owners shall have on file, or be able to readily provide, a document ordata base identifying the normal and emergency ratings of all of theirtransmission facilities (e.g., lines, transformers, reactive devices, terminalequipment, and storage devices) that are part of the bulk interconnectedtransmission systems. Seasonal variations in ratings shall be included asappropriate.

The ratings shall be consistent with the methodology(ies) for determining facilityratings (Standard II.C. S1, M1) and shall be updated as facility changes occur.The ratings shall be provided to the Regions and NERC on request (30 businessdays).

Guides

G1. System modeling should use facility ratings based on weather assumptionsappropriate for the seasonal (demand) conditions being evaluated.

G2. Facility ratings should be based on or adhere to applicable national electricalcodes and electric industry rating practices consistent with good engineeringpractice.

G3. The ratings of bypass equipment do not need to be included in the facility ratingdetermination. However, if it is the most limiting element, it should be identifiedand made available to the system operator. If an equipment failure results inextended use of bypass equipment, then the facility rating should be adjusted inthe model and the Region and impacted operating entities should be informed.

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Introduction

Actual demand data is needed for forecasting future electrical requirements, reliabilityassessments of past electric system events, load diversity studies, and validation of databases.

Forecast demand data is needed for system modeling and the analysis of the adequacy andsecurity of the interconnected bulk electric systems, and for identifying the need and timing ofsystem reinforcements to reliably supply customer electrical requirements.

Actual and forecast demand data generally includes hourly, monthly, and annual demands andmonthly and annual net energy for load. This data may be required on an aggregated Regional,subregional, power pool, individual system basis, or on a dispersed transmission substation basisfor system modeling and reliability analysis.

In addition to demands and net energy for load, that portion of demand that is included in or partof controllable demand-side management programs and which may be interrupted by systemoperators also may be required in evaluating the adequacy and security of the interconnectedbulk electric systems.

Standards

S1. Actual demands and net energy for load data shall be provided on an aggregatedRegional, subregional, power pool, individual system, or load serving entity basis.Actual demand data on a dispersed substation basis shall be supplied when requested.

Forecast demands and net energy for load data shall be developed and maintained onan aggregated Regional, subregional, power pool, individual system, or load servingentity basis. Forecast demand data shall also be developed on a dispersed substationbasis.

S2. Controllable demand-side management (interruptible demands and direct controlload management) programs and data shall be identified and documented.

Measurements

M1. The entities responsible for the reliability of the interconnected transmissionsystems, in conjunction with the Regions, shall have documentation identifyingthe scope and details of the actual and forecast (a) demand data, (b) net energy forload data, and (c) controllable demand-side management data to be reported forsystem modeling and reliability analysis.

The aggregated and dispersed data submittal requirements shall ensure thatconsistent data is supplied for Standards IB, IIA, and IID.

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The documentation of the scope and details of the data reporting requirementsshall be available on request (five business days).

M2. The reporting procedures that are developed shall ensure that customer demandsare not double counted or omitted in reporting actual or forecast demand data oneither an aggregated or dispersed basis within an area or Region. (S1)

M3. Actual and forecast customer demand data and controllable demand-sidemanagement data reported to government agencies shall be consistent with datareported to those entities responsible for the reliability of the interconnectedtransmission systems, the Regions, and NERC. (S1, S2)

M4. The following information shall be provided annually on an aggregated Regional,subregional, power pool, individual system, or load serving entity basis to NERC,the Regions, and those entities responsible for the reliability of the interconnectedtransmission systems as specified by the documentation in Standard II.D.S1-S2,M1.

1. Integrated hourly demands in megawatts (MW) for the prior year.

2. Monthly and annual peak hour actual demands in MW and net energy forload in gigawatthours (GWh) for the prior year.

3. Monthly peak hour forecast demands in MW and net energy for load inGWh for the next two years.

4. Annual peak hour forecast demands (summer and winter) in MW and annualnet energy for load in GWh for at least five years and up to ten years intothe future, as requested.

M5. The following information shall be provided on a dispersed substation basis toNERC, the Regions, and those entities responsible for the reliability of theinterconnected transmission systems:

a. Seasonal peak hour actual demands in MW and Mvars for the prior year(as defined in M1 and M2).

b. Seasonal peak hour forecast demands in MW and Mvars (as defined inM1 and M2).

M6. The actual and forecast customer demand data reported on either an aggregated ordispersed basis shall:

a. indicate whether the demand data of nonmember entities within an areaor Region are included, and

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b. address assumptions, methods, and the manner in which uncertaintiesare treated in the forecasts of aggregated peak demands and net energyfor load.

Full compliance requires items (a) and (b) to be addressed as described in thereporting procedures developed for Measurement M1 of this Standard II.D.Current information on items a) and b) shall be reported to NERC, the Regions,and those entities responsible for the reliability of the interconnected transmissionsystems on request (within 30 days). (S1)

M7. Assumptions, methods, and the manner in which uncertainties are addressed inthe forecasts of aggregated peak demands and net energy for load shall beprovided to the Regions and NERC on request. (S1)

M8. The actual and forecast demand data used in system modeling and reliabilityanalyses (by the entities responsible for the reliability of the interconnectedtransmission systems, the Regions, and NERC) shall be consistent with the actualand forecast demand data provided under this II.D. Standard on Actual andForecast Demands. (S1)

M9. Customer demands that are included in or part of controllable demand-sidemanagement programs, such as interruptible demands and direct control loadmanagement, shall be separately provided on an aggregated Regional,subregional, power pool, and individual system basis to NERC, the Regions, andthose entities responsible for the reliability of the interconnected transmissionsystems on request. (S2)

M10. Forecasts of interruptible demands and direct control load management data shallbe provided annually for at least five years and up to ten years into the future, asrequested, for summer and winter peak system conditions to NERC, the Regions,and those entities responsible for the reliability of the interconnected transmissionsystems as specified by the documentation in Standard II.D.S1-S2, M1.

M11. The amount of interruptible demands and direct control load management shall bemade known to system operators and security center coordinators on request.

Full compliance requires the reporting of this data to system operators andsecurity center coordinators with 30 days of a request. (S2)

M12. Forecasts shall clearly document how the demand and energy effects of demand-side management programs (such as conservation, time-of-use rates, interruptibledemands, and direct control load management) are addressed.

Information detailing how demand-side management measures are addressed inthe forecasts of peak demand and annual net energy for load shall be inclueded inthe data reporting procedures of Measurement M1 of this Standard II.D.

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Documentation on the treatment of demand-side management programs shall beavailable to NERC on request (within 30 days). (S2)

Guides

G1. System modeling and reliability analyses may be required for more than a five-year period for several reasons including review or comparison of results fromprevious studies, regulatory requirements, long lead-time facilities (e.g.,transmission lines), and government requirements (e.g., construction and/orenvironmental permits).

G2. Actual and forecast demand data and forecast controllable demand-side manage-ment data should be provided on either an aggregated or dispersed basis in anappropriate common format to ensure consistency in reporting and to facilitateuse of the data by the entities responsible for the reliability of the interconnectedtransmission systems, the Regions, and NERC.

G3. Weather normalized data, when provided in addition to actual data, should beidentified as such and reconciled as appropriate.

G4. The characteristics of demand-side management programs used in assessingfuture resource adequacy should generally include:

• consistent program ratings (demand and energy), including seasonalvariations

• effect on annual load shape• availability, effectiveness, and diversity• contractual arrangements• expected program duration• effects (demand and energy) of multiple programs

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(Dynamic)

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Introduction

The various components of customer demand respond differently to changes in system voltageand frequency. Seasonal and time-of-day variations may also affect the components andresponse characteristics of customer demands. Accurate representation of these customerdemand characteristics is needed in system modeling since they can have important effects onsystem reliability.

Standard

S1. Representative frequency and voltage characteristics of customer demands (real andreactive power) required for the analysis of the reliability of the interconnectedtransmission systems shall be developed and maintained.

Measurements

M1. The entities responsible for the reliability of the interconnected transmissionsystems, in conjunction with the Regions, shall develop a plan for determiningand promoting the accuracy of the representation of customer demands, identifythe scope and specificity of the frequency and voltage characteristics of customerdemands, and determine the procedures and schedule for data reporting.

Documentation of these customer demand characteristics (dynamic) plans andreporting procedures shall be provided to NERC and the Regions on request. (S1)

M2. The NERC System Dynamics Database Working Group or its successor group(s)shall maintain and publish customer demand characteristics requirements in its“procedural manual” pertaining to the Eastern Interconnection. Similar“procedural manuals” shall be maintained and published by the Western (WECC),ERCOT, and Hydro-Québec1 Interconnections. These procedural manuals shallinclude plans for determining and promoting the accuracy of the representation ofcustomer demands. (S1)

M3. Load-serving entities shall provide customer demand characteristics to theRegions and those entities responsible for the reliability of the interconnectedtransmission systems in compliance with the respective procedural manuals forthe modeling of portions or all of the four NERC Interconnections: Eastern,Western, ERCOT, and Hydro-Québec.4 (S1)

1Hydro-Québec uses the Procedural Manual of the Eastern Interconnection.

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Guides

G1. The representation of customer demands should generally include a combinationof constant MVA, constant current, and constant impedance for real and reactivepower components and frequency dependence, as appropriate.

G2. Special demand models for significant frequency and voltage dependent customerdemands, such as fluorescent lighting or motors, should be provided on request.

G3. Demand characteristics for zones or areas within electric systems or at substationbuses should reflect the composition of the demand at those locations.

G4. The voltage and frequency characteristics of customer demands that are used insystem models should be representative of seasonal and time-of-day variations, asappropriate.

G5. The representation of customer demand characteristics should be periodicallyreviewed and field tested, as appropriate, to ensure the accuracy of the demandmodeling.

G6. The sensitivity of simulation results to the demand models should be evaluated.High sensitivity demands (e.g., motors and certain substation demands) shouldgenerally be represented by more detailed models.

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Protection and control systems are essential to the reliable operation of the interconnectedtransmission networks. They are designed to automatically disconnect components from thetransmission network to isolate electrical faults or protect equipment from damage due tovoltage, current, or frequency excursions outside of the design capability of the facilities.Control systems are those systems that are designed to automatically adjust or maintain systemparameters (voltages, facility loadings, etc.) within pre-defined limits or cause facilities to bedisconnected from or connected to the network to maintain the integrity of the overall bulkelectric systems.

The objectives for protection and control systems generally include:

• DEPENDABILITY - a measure of certainty to operate when required,• SECURITY - a measure of certainty not to operate falsely,• SELECTIVITY - the ability to detect an electrical fault and to affect the least amount

of equipment when removing or isolating an electrical fault or protecting equipmentfrom damage, and

• ROBUSTNESS - the ability of a control system to work correctly over the full range ofexpected steady-state and dynamic system conditions.

A reliable protection and control system requires an appropriate level of protection and controlsystem redundancy. Increased redundancy improves dependability but it can also decreasesecurity through greater complexity and greater exposure to component failure.

Protection and control system reliability is also dependent upon sound testing and maintenancepractices. These practices include defining what, when, and how to test equipment calibrationand operability, performing preventive maintenance, and expediting the repair of faultyequipment.

Diagnostic tools, such as fault and disturbance recorders, can provide a record of protection andcontrol system performance under various transmission system conditions. These records areoften the only means to diagnose protection and control anomalies. Such information is alsocritical in determining the causes of system disturbances, the sequence of disturbance events, anddeveloping necessary corrective and preventive actions. In some instances, these recordsprovide information about incipient conditions that would lead to future transmission systemproblems.

Coordination of protection and control systems is vital to the reliability of the transmissionnetworks. The reliability of the transmission network can be jeopardized by unintentional andunexpected automatic control actions or loss of facilities caused by misoperation oruncoordinated protection and control systems. If protection and control systems are not properlycoordinated, a system disturbance or contingency event could result in the unexpected loss ofmultiple facilities. Such unexpected consequences can result in unknowingly operating theelectric systems under unreliable conditions including the risk of a blackout, if the event shouldoccur.

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The design of protection and control systems must be coordinated with the overall design andoperation of the generation and transmission systems. Proper coordination requires an under-standing of:

• The characteristics, operation, and behavior of the generation and transmission systemsand their protection and control,

• Normal and contingency system conditions, and• Facility limitations that may be imposed by the protection and control systems.

Coordination requirements are specifically addressed in the areas of communications, datamonitoring, reporting, and analysis throughout the Standards, Measurements, and Guidesunder System Protection and Control (III).

The NERC Planning Standards, Measurements, and Guides pertaining to System Protectionand Control (III) are provided in the following sections:

A. Transmission Protection SystemsB. Transmission Control DevicesC. Generation Control and ProtectionD. Underfrequency Load SheddingE. Undervoltage Load SheddingF. Special Protection Systems

These Standards, Measurements, and Guides shall apply to all protection and control systemsnecessary to achieve interconnected transmission network performance as described in theStandards on System Adequacy and Security (I) in this report.

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Systems

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Introduction

The goal of transmission protection systems is to ensure that faults within the intended zone ofprotection are cleared as quickly as possible. When isolating an electrical fault or protectingequipment from damage, these protection systems should be designed to remove the leastamount of equipment from the transmission network. They should also not erroneously trip forfaults outside the intended zones of protection or when no fault has occurred.

The need for redundancy in protection systems should be based on an evaluation of the systemconsequences of the failure or misoperation of the protection system and the need to maintainoverall system reliability.

Standards

S1. Transmission protection systems shall be provided to ensure the system performancerequirements as defined in the I.A. Standards on Transmission Systems andassociated Table I.

S2. Transmission protection systems shall provide redundancy such that no singleprotection system component failure would prevent the interconnected transmissionsystems from meeting the system performance requirements of the I.A. Standards onTransmission Systems and associated Table I.

S3. All transmission protection system misoperations shall be analyzed for cause andcorrective action.

S4. Transmission protection system maintenance and testing programs shall be developedand implemented.

Measurements

M1. Transmission or protection system owners shall review their transmissionprotection systems for compliance with the system performance requirements ofthe I.A. Standards on Transmission Systems and associated Table I. Any non-compliance shall be documented, including a plan for achieving compliance.Documentation of protection system reviews shall be provided to NERC, theRegions, and those entities responsible for the reliability of the interconnectedtransmission systems on request. (S1)

M2. Where redundancy in the protection systems due to single protection systemcomponent failures is necessary to meet the system performance requirements ofthe I.A. Standards on Transmission Systems and associated Table I, thetransmission or protection system owners shall provide, as a minimum, separateac current inputs and separately fused dc control voltage with new or upgraded

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protection system installations. Breaker failure protections need not beduplicated. (S2)

Each Region shall also develop a plan for reviewing the need for redundancy in itsexisting transmission protection systems and for implementing any requiredredundancy. Documentation of the protection system redundancy reviews shall beprovided to NERC, the Regions, and those entities responsible for the reliability ofthe interconnected transmission systems on request. (S2)

M3. Each Region shall have a procedure for the monitoring, review, analysis, andcorrection of transmission protection system misoperations. The Regionalprocedure shall include the following elements:

1. Requirements for monitoring and analysis of all transmission protectivedevice misoperations.

2. Description of the data reporting requirements (periodicity and format) forthose misoperations that adversely affect the reliability of the bulk electricsystems as specified by the Region.

3. Process for review, follow up, and documentation of corrective action plansfor misoperations.

4. Identification of the Regional group responsible for the procedure and theprocess for Regional approval of the procedure.

5. Regional definition of misoperations.

Documentation of the Regional procedure shall be maintained and provided toNERC on request (within 30 days). (S3)

M4. Transmission protection system owners shall have a protection systemmaintenance and testing program in place. This program shall include protectionsystem identification, schedule for protection system testing, and schedule forprotection system maintenance.

Documentation of the program and its implementation shall be provided to theappropriate Regions and NERC on request (within 30 days). (S4)

M5 Transmission protection system owners shall analyze all protection systemmisoperations and shall take corrective actions to avoid future misoperations.

Documentation of the misoperation analyses and corrective actions shall beprovided to the affected Regions and NERC on request (within 30 days)according to the Regional procedures of Measurement III.A. S3, M3.

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Guides

G1. Protection systems should be designed to isolate only the faulted electric systemelement(s), except in those circ*mstances where additional elements must beremoved from service intentionally to preserve electric system integrity.

G2. Breaker failure protection systems, either local or remote, should be provided anddesigned to remove the minimum number of elements necessary to clear a fault.

G3. The relative effects on the interconnected transmission systems of a failure of theprotection systems to operate when required versus an unintended operationshould be weighed carefully in selecting design parameters.

G4. Protection systems and their associated maintenance procedures should bedesigned to minimize the likelihood of personnel error, such as incorrectoperation and inadvertent disabling.

G5. Physical and electrical separation should be maintained between redundantprotection systems, where practical, to reduce the possibility of both systemsbeing disabled by a single event or condition.

G6. Communications channels required for protection system operation should beeither continuously monitored, or automatically or manually tested.

G7. Models used for determining protection settings should take into accountsignificant mutual and zero sequence impedances.

G8. The design of protection systems, both in terms of circuitry and physicalarrangement, should facilitate periodic testing and maintenance.

G9. Protection and control systems should be functionally tested, when initiallyplaced in service and when modifications are made, to verify the dependabilityand security aspects of the design.

G10. Protection system applications should be reviewed whenever significant changesin generating sources, transmission facilities, or operating conditions areanticipated.

G11. The protection system testing program should include provisions for relaycalibration, functional trip testing, communications system testing, and breakertrip testing.

G12. Generation and transmission protection systems should avoid tripping for stablepower swings on the interconnected transmission systems.

G13. When two independent protection systems are required, dual circuit breaker tripcoils should be considered.

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G14. Where each of two protection systems are protecting the same facility, theequipment and communications channel for each system should be separatedphysically and designed to minimize the risk of both protection systems beingdisabled simultaneously by a single event or condition.

G15. Automatic reclosing or single-pole switching of transmission lines should be usedwhere studies indicate enhanced system stability margins are necessary. However,the possible effects on the systems of reclosure into a permanent fault need to beconsidered.

G16. Protection system applications and settings should not normally limittransmission use.

G17. Application of zone 3 relays with settings overly sensitive to overload or depressedvoltage conditions should be avoided where possible.

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Introduction

Certain transmission devices are planned and designed to provide dynamic control of electricsystem quantities, and are usually employed as solutions to specific system performance issues.They typically involve feedback control mechanisms using power electronics to achieve thedesired electric system dynamic response. Examples of such equipment and devices include:HVDC links, active or real power flow control and reactive power compensation devices usingpower electronics (e.g., unified power flow controllers (UPFCs), static var compensators(SVCs), thyristor-controlled series capacitors (TCSCs), and in some cases mechanically-switched shunt capacitors and reactors.

In planning and designing transmission control devices, it is important to consider theiroperation within the context of the overall interconnected systems over a variety of operatingconditions. These control devices can be used to avoid degradation of system performance andcascading outages of facilities. If not properly designed, the feedback controls of these devicescan become unstable during weakened system conditions caused by disturbances, and can lead tomodal interactions with other controls in the interconnected systems.

Standard

S1. Transmission control devices shall be planned and designed to meet the systemperformance requirements as defined in the I.A. Standards of the TransmissionSystems and associated Table I. These devices shall be coordinated with other controldevices within a Region and, where appropriate, with neighboring Regions.

Measurements

M1. When planning new or substantially modified transmission control devices,transmission owners shall evaluate the impact of such devices on the reliability ofthe interconnected transmission systems. The assessment shall include sufficientmodeling of the details of the dynamic devices and encompass a variety ofcontingency system conditions. The assessment results shall be provided to theRegions and NERC on request. (S1)

M2. Transmission owners shall provide transmission control device models and data,suitable for use in system modeling, to the Regions and NERC on request.Preliminary data on these devices shall be provided prior to their in-service dates.Validated models and associated data shall be provided following installation andenergization. (S1)

M3. The transmission owners or operators shall document and periodically (at leastevery five years or as required by changes in system conditions) review thesettings and operating strategies of the control devices. Documentation shall beprovided to the Regions and NERC on request. (S1)

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Guides

G1. Coordinated control strategies for the operation of transmission control devicesmay require switching surge studies, harmonic analyses, or other special studies.

G2. For HDVC links in parallel with ac lines, supplementary control should beconsidered so that the HDVC links provide synchronizing and damping power forinterconnected generators. Use of HDVC links to stabilize system ac voltagesshould be considered.

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Protection

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Introduction

Generator excitation and prime mover controls are key elements in ensuring electric systemstability and reliability. These controls must be coordinated with generation protection tominimize generator tripping during disturbance-caused abnormal voltage, current, and frequencyconditions. Generators are the primary method of electric system dynamic voltage control, andtherefore good performance of excitation equipment (exciter, voltage regulator, and, ifapplicable, power system stabilizer) is essential for electric system stability. Prime movercontrols (governors) are the primary method of system frequency regulation.

Generator control and protection must be planned and designed to provide a balance between theneed for the generator to support the interconnected electric systems during abnormal conditionsand the need to adequately protect the generating equipment from damage. Unnecessarygenerator tripping during a disturbance aggravates the loading conditions on the remaining on-line generators and can lead to a cascading failure of the interconnected electric systems.

Accurate data that describes generator characteristics and capabilities is essential for the studiesneeded to ensure the reliability of the interconnected electric systems. Protection characteristicsand settings affecting electric system reliability must be provided as requested.

Standards

S1. All synchronous generators connected to the interconnected transmission systemsshall be operated with their excitation system in the automatic voltage control modeunless approved otherwise by the transmission system operator.

S2. Generators shall maintain a network voltage or reactive power output as required bythe transmission system operator within the reactive capability of the units.Generator step-up and auxiliary transformers shall have their tap settingscoordinated with electric system voltage requirements.

S3. Temporary excursions in voltage, frequency, and real and reactive power output thata generator shall be able to sustain shall be defined and coordinated on a Regionalbasis.

S4. Voltage regulator controls and limit functions (such as over and under excitation andvolts/hertz limiters) shall coordinate with the generator’s short duration capabilitiesand protective relays.

S5. Prime mover control (governors) shall operate with appropriate speed/loadcharacteristics to regulate frequency.

S6. All generation protection system trip misoperations shall be analyzed for cause andcorrective action.

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S7. Generation protection system maintenance and testing programs shall be developedand implemented.

Measurements

M1. Generation equipment owners shall provide, upon request, the Region andtransmission system operator a log that specifies the date, duration, and reason foreach period when the generator was not operated in the automatic voltage controlmode. The procedures for reporting the data shall address generating unitexemption criteria and shall require documentation of those generating units thatare exempt from a portion or all of these reporting requirements. (S1)

M2. When requested by the transmission system operator, the generating equipmentowner shall provide a log that specifies the date, duration, and reason for agenerator not maintaining the established network voltage schedule or reactivepower output. (S2)

M3. The generation equipment owner shall provide the transmission system operatorwith the tap settings and available ranges for generator step-up and auxiliarytransformers. When tap changes are necessary to coordinate with electric systemvoltage requirements, the transmission system operator shall provide thegeneration equipment owner with a report that specifies the required tap changesand technical justification for these changes. The procedures for reporting the datashall address generating unit exemption criteria and shall require documentation ofthose generating units that are exempt from a portion or all of these reportingrequirements. (S2)

M4. When requested, generating equipment owners shall provide the Region andtransmission system operator with the operating characteristics of any generator’sequipment protective relays or controls that may respond to temporary excursionsin voltage, frequency, or loading with actions that could lead to tripping of thegenerator. The more common protective relays include volts per hertz, loss ofexcitation, underfrequency, overspeed, and backup distance. (S3)

M5. Upon request, generating equipment owners shall provide the Region andtransmission system operator with information that describes how generatorcontrols coordinate with the generator’s short term capabilities and protectiverelays. (S4)

M6. Overexcitation limiters, when used, shall be coordinated with the thermalcapability of the generator field winding. After allowing temporary field currentoverload, the limiter shall operate through the automatic ac voltage regulator toreduce field current to the continuous rating. Return to normal ac voltage

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regulation after current reduction shall be automatic. The overexcitation limitershall be coordinated with overexcitation protection so that overexcitationprotection only operates for failure of the voltage regulator/limiter. (S4)

M7. Upon request, generating equipment owners shall provide the Region ortransmission system operator with information that describes the characteristics ofthe speed/load governing system. Boiler or nuclear reactor control shall becoordinated to maintain the capability of the generator to aid control of systemfrequency during an electric system disturbance to the extent possible whilemeeting the safety requirements of the plant. Nonfunctioning or blockedspeed/load governor controls shall be reported to the Region and transmissionsystem operator. (S5)

M8. Each Region shall have a process in place for the monitoring, notification, andanalysis of all generation protection trip operations. Documentation of protectiontrip misoperations shall be provided to the affected Regions and NERC onrequest. (S6)

M9. Generation equipment owners shall have a generation protection system mainte-nance and testing program in place. Documentation of the implementation ofprotection system maintenance and testing shall be provided to the appropriateRegions and NERC on request. (S7)

Guides

G1. Power system stabilizers improve damping of generator rotor speed oscillations.They should be applied to a unit where studies have determined the possibility ofunit or system instability and where the condition can be improved or correctedby the application of a power system stabilizer. Power system stabilizers shouldbe designed and tuned to have a positive damping effect on local generatoroscillations and on inter-area oscillations without deteriorating turbine/generatorshaft torsional oscillation damping.

G2. Generators and turbines should be designed and operated so that there is additionalreactive power capability that can be automatically supplied to the system during adisturbance.

G3. Generator control and protection should be periodically tested to the extentpractical to ensure the generator plant can provide the designed control, andoperate without tripping for specified voltage, frequency, and load excursions.Control responses should be checked periodically to validate the model data usedin simulation studies.

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G4. New or upgraded excitation equipment should consider high initial response, asinherent in brushless or static exciters.

G5. Generator step-up transformer and auxiliary transformers should have tap settingsthat are coordinated with electric system voltage control requirements and whichdo not limit maximum use of the reactive capability (lead and lag) of thegenerators.

G6. Prime mover control (governors) should operate freely to regulate frequency. Inthe absence of Regional requirements for the speed/load control characteristics,governor droop should generally be set at 5% and total governor deadband(intentional plus unintentional) should generally not exceed +/- 0.06%. Thesecharacteristics should in most cases ensure a coordinated and balanced responseto grid frequency disturbances. Prime movers operated with valves or gates wideopen should control for overspeed/overfrequency.

G7. Prime mover overspeed controls to the extent practical should be designed andadjusted to prevent boiler upsets and trips during partial load rejectioncharacterized by abnormally high system frequency.

G8. Generator voltage regulators to the extent practical should be tuned for fastresponse to step changes in terminal voltage or voltage reference. It is preferableto run the step change in voltage tests with the generator not connected to thesystem so as to eliminate the system effects on the generator voltage. Terminalvoltage overshoot should generally not exceed 10% for an open circuit stepchange in voltage test.

G9. New or upgraded excitation equipment to the extent practical should have anexciter ceiling voltage that is generally not less than 1.5 times the rated outputfield voltage.

G10. Power plant auxiliary motors should not trip or stall for momentary undervoltageassociated with the contingencies as defined in Categories A, B, and C of the I.A.Standards on Transmission Systems, unless the loss of the associated generatingunit(s) would not cause a violation of the contingency performance requirements.

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Introduction

A coordinated automatic underfrequency load shedding (UFLS) program is required to helppreserve the security of the generation and interconnected transmission systems during majordeclining system frequency events. Such a program is essential to minimize the risk of totalsystem collapse, protect generating equipment and transmission facilities against damage,provide for equitable load shedding (interruption of electric supply to customers), and helpensure the overall reliability of the interconnected systems.

Load shedding resulting from a system underfrequency event should be controlled so as tobalance generation and customer demand (load), permit rapid restoration of electric service tocustomer demand that has been interrupted, and when necessary re-establish transmissioninterconnection ties.

Standards

S1. A Regional UFLS program shall be planned and implemented in coordination withother UFLS programs, if any, within the Region and, where appropriate, withneighboring Regions. The Regional UFLS program shall be coordinated withgeneration control and protection systems, undervoltage and other load sheddingprograms, Regional load restoration programs, and transmission protection andcontrol systems.

Measurements

M1. Each Region shall develop, coordinate, and document a Regional UFLS program,which shall include the following:

a. Requirements for coordination of UFLS programs within the subregions,Region, and, where appropriate, among Regions.

b. Design details including size of coordinated load shedding blocks (% ofconnected load), corresponding frequency set points, intentional delays,related generation protection, tie tripping schemes, islanding schemes,automatic load restoration schemes, or any other schemes that are part ofor impact the UFLS programs.

c. A Regional UFLS program database. This database shall be updated asspecified in the Regional program (but at least every five years) andshall include sufficient information to model the UFLS program indynamic simulations of the interconnected transmission systems.

d. Technical assessment and documentation of the effectiveness of thedesign and implementation of the Regional UFLS program. Thistechnical assessment shall be conducted periodically and shall (at leastevery five years or as required by changes in system conditions) include,but not be limited to:

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1. A review of the frequency set points and timing, and2. Dynamic simulation of possible disturbance that cause the Region

or portions of the Region to experience the largest imbalancebetween demand (load) and generation.

e. Determination, as appropriate, of maintenance, testing, and calibrationrequirements by member systems.

Documentation of each Region’s UFLS program and its database informationshall be current and provided to NERC on request (within 30 days).

Documentation of the current technical assessment of the UFLS program shallalso be provided to NERC on request (within 30 days). (S1)

M2. Those entities owning or operating an UFLS program shall ensure that theirprograms are consistent with Regional UFLS program requirements as specified inMeasurement M1. Such entities shall provide and annually update their UFLSdata as necessary for the Region to maintain and update and UFLS program asspecified in Measurement M1.

The documentation of an entity's UFLS program shall be provided to the Regionon request (within 30 days). (S1)

M3. UFLS equipment owners shall have an UFLS equipment maintenance and testingprogram in place. This program shall include UFLS equipment identification, theschedule for UFLS equipment testing, and the schedule for UFLS equipmentmaintenance.

These programs shall be maintained and documented, and the results ofimplementation shall be provided to the Regions and NERC on request (within 30days).

M4. Those entities owning or operating UFLS programs shall analyze and documenttheir UFLS program performance in accordance with Standard III.D. S1-S2, M1,including the performance of UFLS equipment and program effectivenessfollowing system events resulting in system frequency excursions below theinitializing set points of the UFLS program. The analysis shall include, but not belimited to:

1. A description of the event including initiating conditions2. A review of the UFLS set points and tripping times3. A simulation of the event4. A summary of the findings

Documentation of the analysis shall be provided to the Regions and NERC onrequest 90 days after the system event.

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Guides

G1. The UFLS programs should occur in steps related to frequency or rate offrequency decay as determined from system simulation studies. These studies arecritical to coordinate the amount of load shedding necessary to arrest frequencydecay, minimize loss of load, and permit timely system restoration.

G2. The UFLS programs should be coordinated with generation protection andcontrol, undervoltage and other load shedding programs, Regional loadrestoration programs, and transmission protection and control.

G3. The technical assessment of UFLS programs should include reviews of systemdesign and dynamic simulations of disturbances that would cause the largestexpected imbalances between customer demand and generation. Both peak andoff-peak system demand levels should be considered. The assessments shouldpredict voltage and power transients at a widespread number of locations as wellas the rate of frequency decline, and should reflect the operation ofunderfrequency sensing devices. Potential system separation points and resultingsystem islands should be determined.

G4. Except for qualified automatic isolation plans, the opening of transmissioninterconnections by underfrequency relaying should be considered only after thecoordinated load shedding program has failed to arrest system frequency declineand intolerable system conditions exist.

G5. A generation-deficient entity may establish an automatic islanding plan in lieu ofautomatic load shedding, if by doing so it removes the burden it has imposed onthe transmission systems. This islanding plan may be used only if it complies withthe Regional UFLS program and leaves the remaining interconnected bulk electricsystems intact, in demand and generation balance, and with no unacceptable highvoltages.

G6. In cases where area isolation with a large surplus of generation compared todemand can be anticipated, automatic generator tripping or other remedialmeasures should be considered to prevent excessive high frequency and resultantuncontrolled generator tripping and equipment damage.

G7. UFLS relay settings and the underfrequency protection of generating units as wellas any other manual or automatic actions that can be expected to occur underconditions of frequency decline should be coordinated.

G8. The UFLS program should be separate, to the extent possible, from manual loadshedding schemes such that the same loads are not shed by both schemes.

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G9. Generator underfrequency protection should not operate until the UFLS programshave operated and failed to maintain the system frequency at an operable level.This sequence of operation is necessary both to limit the amount of load sheddingrequired and to help the systems avoid a complete collapse. Where this sequenceis not possible, UFLS programs should consider and compensate for anygenerator whose underfrequency protection is required to operate before a portionof the UFLS program.

G10. Plans to shed load automatically should be examined to determine if unacceptableoverfrequency, overvoltage, or transmission overloads might result. Potentialunacceptable conditions should be mitigated.

If overfrequency is likely, the amount of load shed should be reduced orautomatic overfrequency load restoration should be provided.

If overvoltages are likely, the load shedding program should be modified (e.g.,change the geographic distribution) or mitigation measures (e.g., coordinatedtripping of shunt capacitors or reactors) should be implemented to minimize thatprobability.

If transmission capabilities will likely be exceeded, the underfrequency relaysettings (e.g., location, trip frequency, or time delay) should be altered or otheractions taken to maintain transmission loadings within capabilities.

G11. Where the UFLS program fails to arrest frequency decline, generators may beisolated with local load to minimize loss of generation and enable timely systemrestoration.

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Introduction

Electric systems that experience heavy loadings on transmission facilities with limited reactivepower control can be vulnerable to voltage instability. Such instability can cause tripping ofgenerators and transmission facilities resulting in loss of customer demand as well as systemcollapse. Since voltage collapse can occur suddenly, there may not be sufficient time foroperator actions to stabilize the systems. Therefore, a load shedding scheme that isautomatically activated as a result of undervoltage conditions in portions of a system can be aneffective means to stabilize the interconnected systems and mitigate the effects of a voltagecollapse.

It is imperative that undervoltage relays be coordinated with other system protection and controldevices used to interrupt electric supply to customers.

Standards

S1. Automatic undervoltage load shedding (UVLS) programs shall be planned andimplemented in coordination with other UVLS programs in the Region and, whereappropriate, with neighboring Regions.

S2. All UVLS programs shall be coordinated with generation control and protectionsystems, underfrequency load shedding programs, Regional load restorationprograms, and transmission protection and control programs.

Measurements

M1. Those entities owning or operating UVLS programs shall coordinate anddocument their UVLS programs including descriptions of the following:

a. Coordination of UVLS programs within the subregions, the Region, and,where appropriate, among Regions.

b. Coordination of UVLS programs with generation protection and control,UFLS programs, Regional load restoration programs, and transmissionprotection and control programs.

c. Design details including size of customer demand (load) blocks (% ofconnected load), corresponding voltage set points, relay and breakeroperating times, intentional delays, related generation protection,islanding schemes, automatic load restoration schemes, or any otherschemes that are part of or impact the UVLS programs.

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Documentation of the UVLS programs shall be provided to the appropriateRegions and NERC on request. (S1, S2)

M2. Those entities owning or operating UVLS programs shall ensure that theirprograms are consistent with any Regional UVLS programs and that existincluding automatically shedding load in the amounts and at locations, voltages,rates, and times consistent with any Regional requirements. (S1)

M3. Each Region shall maintain and annually update an UVLS program database.This database shall include sufficient information to model the UVLS program indynamic simulations of the interconnected transmission systems. (S1)

M4. Those entities owning or operating UVLS programs shall periodically (at leastevery five years or as required by changes in system conditions) conduct anddocument a technical assessment of the effectiveness of the design andimplementation of its UVLS program. Documentation of the UVLS technicalassessment shall be provided to the appropriate Regions and NERC on request.(S1)

M5. Those entities owning or operating UVLS programs shall have a maintenanceprogram to test and calibrate their UVLS relays to ensure accuracy and reliableoperation. Documentation of the implementation of the maintenance programshall be provided to the appropriate Regions and NERC on request. (S1)

M6. Those entities owning or operating an UVLS program shall analyze and documentall system undervoltage events below the initiating set points of their UVLSprograms. Documentation of the analysis shall be provided to the appropriateRegions and NERC on request. (S1)

Guides

G1. UVLS programs should be coordinated with other system protection and controlprograms (e.g., timing of line reclosing, tap changing, overexcitation limiting,capacitor bank switching, and other automatic switching schemes).

G2. Automatic UVLS programs should be coordinated with manual load sheddingprograms.

G3. Manual load shedding programs should not include, to the extent possible,customer demand that is part of an automatic UVLS program.

G4. Assessments of UVLS programs should include system dynamic simulations thatrepresent generator overexcitation limiters, load restoration dynamics (tapchanging, motor dynamics), and shunt compensation switching.

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G5. Plans to shed load automatically should be examined to determine if acceptableoverfrequency, overvoltage, or transmission overloads might result. Potentialunacceptable conditions should be mitigated.

If overfrequency is likely, the amount of load shed should be reduced orautomatic overfrequency load restoration should be provided.

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Introduction

A special protection system (SPS) or remedial action scheme (RAS) is designed to detectabnormal system conditions and take pre-planned, corrective action (other than the isolation offaulted elements) to provide acceptable system performance. SPS actions, include among others,changes in demand (e.g., load shedding), generation, or system configuration to maintain systemstability, acceptable voltages, or acceptable facility loadings.

The use of an SPS is an acceptable practice to meet the system performance requirements asdefined under Categories A, B, or C of Table I of the I.A. Standards on Transmission Systems.Electric systems that rely on an SPS to meet the performance levels specified by the NERCPlanning Standards must ensure that the SPS is highly reliable.

Examples of SPS misoperation include, but are not limited to, the following:

1. The SPS does not operate as intended.2. The SPS fails to operate when required.3. The SPS operates when not required.

Standards

S1. An SPS shall be designed so that a single SPS component failure, when the SPS wasintended to operate, does not prevent the interconnected transmission system frommeeting the performance requirements defined under Categories A, B, or C of Table1 of the I.A Standards on Transmission Systems.

S2. The inadvertent operation of an SPS shall meet the same performance requirement(Category A, B, or C of Table I of the I.A. Standards on Transmission Systems) asthat required of the contingency for which it was designed, and shall not exceedCategory C.

S3. SPS installations shall be coordinated with other protection and control systems.

S4. All SPS misoperations shall be analyzed for cause and corrective action.

S5. SPS maintenance and testing programs shall be developed and implemented.

Measurements

M1. Each Region whose members use or are planning to use an SPS shall have adocumented Regional review procedure to ensure the SPS complies withRegional criteria and guides and NERC Planning Standards. The Regionalreview procedure shall include:

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1. Description of the process for submitting a proposed SPS for Regionalreview.

2. Requirements to provide data that describes design, operation, and modelingof an SPS.

3. Requirements to demonstrate that the SPS design will meet above SPSStandards S1 and S2.

4. Requirements to demonstrate the proposed SPS will coordinate with otherprotection and control systems and applicable Regional emergencyprocedures.

5. Regional definition of misoperation.6. Requirements for analysis and documentation of corrective action plans for

all SPS misoperations.7. Identification of the Regional group responsible for the Region’s review

procedure and the process for Regional approval of the procedure.8. Determination, as appropriate, of maintenance and testing requirements.

Documentation of the Regional SPS review procedure shall be provided toaffected Regions and NERC, on request (within 30 days). (S1, S2, S3, S4)

M2. A Region that has a member with an SPS installed shall maintain an SPSdatabase. The database shall include the following types of information:

1. Design Objectives – Contingencies and system conditions for which the SPSwas designed,

2. Operation – The actions taken by the SPS in response to disturbanceconditions, and

3. Modeling – Information on detection logic or relay settings that controloperation of the SPS.

Documentation of the Regional database or the information therein shall beprovided to affected Regions and NERC, on request (within 30 days). (S1, S2,S3)

M3. A Region shall assess the operation, coordination, and effectiveness of all SPSsinstalled in the Region at least once every five years for compliance with NERCPlanning Standards and Regional criteria. The Regions shall provide either asummary report or a detailed report of this assessment to affected Regions orNERC, on request (within 30 days). The documentation of the Regional SPSassessment shall include the following elements:

1. Identification of group conducting the assessment and the date theassessment was performed.

2. Study years, system conditions, and contingencies analyzed in the technicalstudies on which the assessment is based and when those technical studieswere performed.

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3. Identification of SPSs that were found not to comply with NERC PlanningStandards and Regional criteria.

4. Discussion of any coordination problems found between an SPS and otherprotection and control systems.

5. Provide corrective action plans for non-compliant SPSs. (S1, S2, S3)

M4. SPS owners shall maintain a list of and provide data for existing and proposedSPSs as defined in Measurement III.F. S1-S3, M2. New or functionally modifiedSPSs shall be reviewed in accordance with the Regional procedures as defined inMeasurement III.F. S1-S4, M1 prior to being placed in service.

Documentation of SPS data and the results of studies that show compliance ofnew or functionally modified SPSs with NERC Planning Standards and Regionalcriteria shall be provided to affected Regions and NERC, on request (within 30days). (S1, S2, S3)

M5. SPS owners shall analyze SPS operations and maintain a record of allmisoperations in accordance with Regional procedures in Measurement III.F. S1-S4, M1. Corrective actions shall be taken to avoid future misoperations.

Documentation of the misoperation analyses and the corrective action plans shallbe provided to the affected Regions and NERC, on request (within 90 days). (S4)

M6. SPS owners shall have an SPS maintenance and testing program in place. Thisprogram shall include the SPS identification, summary of test procedures,frequency of testing, and frequency of maintenance. Documentation of theprogram and its implementation shall be provided to the appropriate Regions andNERC on request (within 30 days). (S5)

Guides

G1. Complete redundancy should be considered in the design of an SPS withdiagnostic and self-check features to detect and alarm when essential componentsfail or critical functions are not operational.

G2. No identifiable common mode events should result in the coincident failure oftwo or more SPS components.

G3. An SPS should be designed to operate only for conditions that require specificprotective or control actions.

G4. As system conditions change, an SPS should be disarmed to the extent that its useis unnecessary.

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G5. SPSs should be designed to minimize the likelihood of personnel error, such asincorrect operation and inadvertent disabling. Test devices or switches should beused to eliminate the necessity for removing or disconnecting wires duringtesting.

G6. The design of SPSs both in terms of circuitry and physical arrangement shouldfacilitate periodic testing and maintenance. Test facilities and test proceduresshould be designed such that they do not compromise the independence ofredundant SPS groups.

G7. SPSs that rely on circuit breakers to accomplish corrective actions should as aminimum use separate trip coils and separately fused dc control voltages.

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NERC/WECC Planning Standards 90

A blackout is a condition where a major portion or all of an electrical network is de-energizedresulting in loss of electric supply to a portion or all of that network’s customer demand. Black-outs will generally take place under two typical scenarios:

• Dynamic instability, and• Steady-state overloads and/or voltage collapse.

Blackouts are possible at all loading levels and all times in the year. Changing generationpatterns, scheduled transmission outages, off-peak loadings resulting from operations of pumpedstorage units, storms, and rapid weather changes among other reasons can all lead to blackouts.Systems must always be alert to changing parameters that have the potential for blackouts.

Actions required for system restoration include identifying resources that will likely be neededduring restoration, determining their relationship with each other, and training personnel in theirproper application. Actual testing of the use of these strategies is seldom practical. Simulationtesting of restoration plan elements or the overall plan are essential preparations towardreadiness for implementation on short notice.

The NERC Planning Standards, Measurements, and Guides pertaining to System Restoration(IV) are provided in the following sections:

A. System Blackstart CapabilityB. Automatic Restoration of Load

These Standards, Measurements, and Guides address only two aspects of an overallcoordinated system restoration plan. From a planning standpoint, it is critical that any overallsystem restoration plans include adequate generating units with system blackstart capability. Itis also important that adequate facilities are planned for the interconnected transmission systemsto accommodate the special requirements of system restoration plans such as switching andsectionalizing strategies, station batteries for dc loads, coordination with under-frequency andundervoltage load shedding programs and Regional or area load restoration plans, and facilitiesfor adequate communications.

Automatic restoration of load following a blackout helps to minimize the duration of interruptionof electric service to customer demands. However, these automatic systems must be coordinatedwith other Regional load restoration activities and included in the components of overall systemrestoration plans.

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Introduction

Following the complete loss of system generation (blackout), it will be necessary to establishinitial generation that can supply a source of electric power to other system generation and beginsystem restoration. These initiating generators are referred to as system blackstart generators.They must be able to self-start without any source of off-site electric power and maintainadequate voltage and frequency while energizing isolated transmission facilities and auxiliaryloads of other generators. Generators that can safely reject load down to their auxiliary load areanother form of blackstart generator that can aid system restoration.

From a planning perspective, a system blackstart capability plan is necessary to ensure that thequantity and location of system blackstart generators are sufficient and that they can performtheir expected functions as specified in overall coordinated Regional system restoration plans.

Standards

S1. A coordinated system blackstart capability plan shall be established, maintained, andverified through analysis indicating how system blackstart generating units willperform their intended functions as required in system restoration plans. Suchblackstart capability plans shall include coordination within and among Regions asappropriate.

S2. Each blackstart generating unit shall be tested to verify that it can be started andoperated without being connected to the system.

Measurements

M1. Each Region shall establish and maintain a system blackstart capability plan thatshall be coordinated, as appropriate, with the blackstart capability plans ofneighboring Regions. Documentation of system blackstart capability plans shallbe provided to NERC on request. (S1)

M2. Regions shall maintain a record of all system blackstart generators within theirrespective areas and update such records on an annual basis. The record shallinclude the name, location, MW capacity, type of unit, date of test, and startingmethod of each system blackstart generating unit. (S1)

M3. The owner or operator of each system blackstart generating unit shall demonstrateat least every five years, through simulation or testing, that the unit can performits intended functions as required in the system restoration plan. Documentationof the analysis shall be provided to the Region and NERC on request. (S1)

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M4. The results of periodic tests of the startup and operation of each system blackstartgenerating unit shall be documented and provided to the Region and NERC onrequest. (S2)

M5. Each Region shall verify that the number, size, and location of system blackstartgenerating units are sufficient to meet system restoration plan expectations. (S1)

Guides

G1. Analyses should ensure that a system blackstart generating unit is capable ofmaintaining adequate regulation of voltage and frequency.

G2. Analyses should include evaluation of blackstart generator protection and controlsystems during the abnormal conditions that will exist during system restoration.

G3. Actual physical testing of system blackstart generating unit procedures should beperformed where practical or feasible.

G4. When limited energy resources (e.g., hydro, pumped storage hydro, compressedair) are used for blackstart, the system blackstart capability plan timing con-siderations should include a range of limiting energy conditions.

NERC/WECC Planning StandardsReferences

NERC/WECC Planning Standards 93

Introduction

If properly coordinated and implemented, automatic restoration of load can be useful tominimize the duration of interruption of electric service to customer demands. However, caremust be taken to ensure that automatic restoration of load does not impede restoration of theinterconnected bulk electric systems.

After automatic load shedding (by either underfrequency or undervoltage relays) has occurred,use of automatic restoration of load after the electric systems have recovered sufficiently(systems stabilized, frequency near nominal, and voltages within appropriate limits) can speedthe reenergization of customer demands and minimize delays in restoring the electric systems.

Standard

S1. Automatic load restoration programs shall be coordinated and in compliance withRegional load restoration programs. These automatic load restoration programsshall be designed to avoid recreating electric system underfrequencies orundervoltages, overloading transmission facilities, or delaying the restoration ofsystem facilities and interconnection tie lines to neighboring systems.

Measurements

M1. Those entities owning or operating an automatic load restoration program shallcoordinate, document, review, and implement their programs in compliance withRegional programs for load restoration. Documentation of automatic loadrestoration programs shall be provided to the appropriate Regions and NERC onrequest. (S1)

M2. Documentation of automatic load restoration programs shall include:

a. A description of how load restoration is coordinated withunderfrequency and undervoltage load shedding programs within theRegion and, where appropriate, among Regions.

b. Automatic load restoration design details including size of coordinatedload restoration blocks (% of connected load), corresponding frequencyor voltage set points, and operating sequence (including relay andbreaker operating times and intentional delays). (S1)

M3. Each Region shall maintain and annually update an automatic load restorationprogram database. This database shall include sufficient information to model theautomatic load restoration programs in dynamic simulations of the interconnectedtransmission systems. (S1)

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M4. Those entities owning or operating an automatic load restoration program shallconduct and document a technical assessment of the effectiveness of the designand implementation of their programs including their relationship to under-frequency and undervoltage load shedding programs in the Region. Docu-mentation of the technical assessments of automatic load restoration programsshall be available to the appropriate Regions and NERC on request. (S1)

M5. Those entities owning or operating automatic load restoration programs shall havea maintenance program to test and calibrate the automatic load restoration relaysto ensure accurate and reliable operation. Documentation of the implementationof the maintenance program shall be provided to the appropriate Regions andNERC on request. (S1)

Guides

G1. Relays installed to restore load automatically should be set with varying andrelatively long time delays, except for that portion of the automatic loadrestoration, if any, that is designed to protect against frequency overshoot.

G2. The design of automatic load restoration programs should consider the systemeffects of reenergizing large blocks of customer demand.

G3. Major interconnection tie lines should generally be restored to service beforeautomatic restoration of load is implemented.

NERC/WECC Planning StandardsReferences

The references in this section are provided as background information for the users ofthe NERC Planning Standards. This list is comprised of recommendations from thevarious members of the NERC Engineering Committee’s subgroups that participatedin the development of the NERC Planning Standards.

Except for NERC references, the references in the following list have not beenreviewed or endorsed by NERC or any of its subgroups. However, these referencesshould aid the reader who wants an understanding of specific technical areas addressedin the NERC Planning Standards.

I.E Transfer Capability

1. NERC Transmission Transfer Capability Task Force, Transmission TransferCapability, Reference Document, May 1995.

2. NERC Transmission Transfer Capability Task Force, Available TransferCapability Definitions and Determination, Reference Document, June 1996.

II.A System Data

1. Multregional Modeling Working Group, NERC Multregional Modeling WorkingGroup Procedural Manual, Revision No. 11, April 1997.

2. System Dynamics Database Working Group, NERC System Dynamics DatabaseWorking Group Procedural Manual, December 1996.

3. U.S. Department of Energy, Energy Information Administration, Instructions forElectronic Reporting of Regional Electricity Supply & Demand Projections(EIA-411), 1996.

III.B Transmission Control Devices

1. J. F. Hauer, “Robust Damping Controls for Large Power Systems,” IEEE ControlSystems Magazine, pp. 12–19, January 1989.

2. IEEE Special Stability Controls Working Group, +Static Var CompensatorModels for Power Flow and Dynamic Performance Simulation, IEEETransactions on Power Systems, Vol. 9, No. 1, pp. 229–240, February 1994.

3. CIGRE Task Force 14–07, “Interaction between DC and AC Systems,” CIGRE,paper 14–09, 1986.

4. CIGRE Working Group 14.07, Guide for Planning DC Links Terminating at ACSystems Locations Having Low Short–Circuit Capacities, Brochure No. 68, June 1992.

5. CIGRE Task Force 38.05.05, Use of DC Converters for VAr Control, Brochure No. 82,August 1993.

NERC/WECC Planning StandardsReferences

6. CIGRE Task Force 38.01.07, CIGRE Technical Brochure on Control of Power stemOscillations, 1997.

III.C Generation Control and Protection

1. P. Kundur, Power System Stability and Control, McGraw-Hill, 1994.

2. IEEE Guide for Synchronous Generator Modeling Practices in Stability Analysis, IEEEStd 110–1991.

3. IEEE Guide for Identification, Testing and Evaluation of the Dynamic Performance ofExcitation Control Systems, IEEE Standard 421.2–1990.

4. IEEE Recommended Practice for Excitation System Models for Power System StabilityStudies, IEEE Std 421.5–1992.

5. IEEE Digital Excitation Task Force, “Computer Models for Representation of Digital-Based Excitation Systems,” IEEE Transactions on Energy Conversion, Vol. 11, No. 3,pp. 607–615, September 1996.

6. IEEE Excitation Limiters Task Force, “Recommended Models for OverexcitationLimiting Devices,” IEEE Transactions on Energy Conversion, Vol. 10, No. 4, pp. 706–712, December 1995.

7. IEEE Excitation Limiters Task Force, “Underexcitation Limiter Models for PowerSystem Stability Studies,” IEEE Transactions on Energy Conversion, Vol. 10, No. 3, pp.524–531, September 1995.

8. J. R. Ribeiro, “Minimum Excitation Limiter Effects on Generator Response to SystemDisturbances,” IEEE Transactions on Energy Conversion, Vol. 6, No. 1, pp. 29–38,March 1991.

9. M. S. Baldwin and D. P. McFadden, “Power Systems Performance as Affected byTurbine-Generator Controls Response During Frequency Disturbances,” IEEETransactions on Power Apparatus and Systems, Vol. PAS-100, No. 5, pp. 2486–2494,May 1981.

10. F. P. deMello, L. N. Hannett, and J. M. Undrill, “Practical Approaches to SupplementaryStabilizing from Accelerating Power,” IEEE Transactions on Power Apparatus andSystems, Vol. PAS-97, pp. 1515–1522, September/October 1978.

11. CIGRE Task Force 38.01.07, CIGRE Technical Brochure on Control of Power SystemOscillations, 1997.

NERC/WECC Planning StandardsReferences

12. American National Standard for Rotating Electrical Machinery - Cylindrical-RotorSynchronous Generators, ANSI C50.13–1989. (Standard gives time-overloadrequirements for generator armature and field windings.)

13. IEEE Std. 122-1985, IEEE Recommended Practice for Functional and PerformanceCharacteristics of Control System for Steam Turbine-Generator Units, IEEE, 1985.

14. EPIC Engineering, Inc., Impacts of Governor Response Changes on the Security ofNorth American Interconnections, EPRI Final Report TR-101080, October 1992(prepared for NERC and available to NERC members).

15. P. Kundur, “A Survey of Utility Experiences with Power Plant Response during PartialLoad Rejections and System Disturbances,” IEEE Transactions on Power Apparatusand Systems, Vol. PAS-100, No. 5, pp. 2471-2475, May 1981.

16. P. B. Johnson, et al., “Maximizing the Reactive Capability of AEP Generating Units,”Proceedings of American Power Conference, April 1990.

17. M. M. Adibi and D. P. Milanicz, “Reactive Capability Limitation of SynchronousMachines,” IEEE Transactions on Power Delivery, Vol. 9, No. 1, pp. 29–40, February1994.

18. N. E. Nilsson and J. Mercurio, “Synchronous Generator Capability Curve Testing andEvaluation,” IEEE Transactions on Power Delivery, Vol. 9, No. 1, pp. 414–424, January1994.

19. A. Panvini and T. J. Yohn, “Field Assessment of Generators Reactive Capability,” IEEETransactions on Power Systems, Vol. 10, No. 1, February 1995.

20. IEEE/PES Transformers Committee, IEEE Guide for Transformers Directly Connectedto Generators, IEEE/ANSI Standard C57.116-1989. (Provides guidance on generatorstep-up transformer tap settings.)

21. CIGRÉ Task Force 38.02.17, Criteria and Countermeasures for Voltage Collapse,CIGRÉ Brochure No. 101, October 1995.

22. IEEE/PES Protective Relaying Committee, IEEE Guide for Abnormal FrequencyProtection for Power Generating Plants, ANSI/IEEE Standard C37.106–1987 (currentlyunder revision).

23. IEEE/PES Protective Relaying Committee, IEEE Guide for AC Generator Protection,IEEE Standard C37.102-1987.

NERC/WECC Planning StandardsReferences

III.D Underfrequency Load Shedding

1. D. W. Smaha, C. R. Rowland, and J. W. Pope, “Coordination of Load Conservation withTurbine-Generator Underfrequency Protection,” IEEE Transactions on Power Apparatusand Systems, Vol. PAS-99, No. 3, pp. 1137–1150, May/June 1980.

2. C. W. Taylor, F. R. Nassief, and R. L. Cresap, +Northwest Power Pool TransientStability and Load Shedding Controls for Generation-Load Imbalances, IEEE actions onPower Apparatus and Systems, Vol. PAS-100, No. 7, pp. 3486–3495, July 1981.

3. K. L. Hicks, “Hybrid Load Shedding is Frequency Based,” IEEE Spectrum, pp. 52–56,February, 1983.

III.E Undervoltage Load Shedding

1. CIGRE Task Force 38.02.17, Criteria and Countermeasures for Voltage Collapse,CIGRE Brochure No. 101, October 1995.

2. C. W. Taylor, Power System Voltage Stability, McGraw-Hill, 1994 (Chapter 7 describes1800 MW of undervoltage load shedding installed in the Puget Sound area).

3. IEEE Power System Relaying Committee Working Group K12, Voltage CollapseMitigation, December 1996 (available for download from IEEE Power EngineeringSociety web site).

4. H. M. Shuh and J. R. Cowan, “Undervoltage Load Shedding-An Ultimate Applicationfor the Voltage Collapse,” Proceedings of the Georgia Tech Protective RelayConference, April 29–May 1, 1992.

III.F Special Protection Systems

1. Kundur, Power System Stability and Control, McGraw-Hill, 1994 (refer to Chapter 17,Methods of Improving Stability).

The NERC Planning Standards were approved by the NERC BOT 1997, 2001, 2002Approved by Planning Coordination Committee June 29, 2001Approved by Board of Trustees August 7, 2001Revisions Approved by Planning Coordination Committee February 28, 2002Revisions Approved by Board of Trustees April 18, 2002Revisions Approved by Planning Coordination Committee June 27, 2002Approved by Board of Directors August 9, 2002Approved by Board of Directors April 10, 2003

WESTERN ELECTRICITY COORDINATING COUNCIL

POWER SUPPLY ASSESSMENT POLICY

PART II

WESTERN ELECTRICITY COORDINATING COUNCIL

POWER SUPPLY ASSESSMENT POLICY Revised April 18, 2002

Western Electricity Coordinating Council

WESTERN ELECTRICITY COORDINATING COUNCIL

POWER SUPPLY ASSESSMENT POLICY

TABLE OF CONTENTS ___________________________________________________________________________

Page INTRODUCTION ......................................................................................................................... 1 PURPOSE OF POWER SUPPLY ASSESSMENT ...................................................................... 1 ASSESSMENT METHODOLOGY.............................................................................................. 2 DATA REQUIREMENTS............................................................................................................. 2 REPORTING OF POWER SUPPLY ADEQUACY..................................................................... 3

WESTERN ELECTRICITY COORDINATING COUNCIL

POWER SUPPLY ASSESSMENT POLICY

INTRODUCTION The Western Electricity Coordinating Council was established to promote the reliable operation of the interconnected bulk power system by the coordination of planning and operation of generating and interconnected transmission facilities. The Planning Coordination Committee assigned the Reliability Subcommittee the task of developing an Adequacy of Supply Assessment Methodology. This document establishes the policy for conducting power supply assessments using the methodology developed by the Reliability Subcommittee. This policy shall be periodically reviewed and revised as experience indicates. PURPOSE OF POWER SUPPLY ASSESSMENT To ensure the reliability of the interconnected bulk electric system, it is necessary to assess both the security and the adequacy of the overall Western Interconnection. This document is focused on the portion of the assessment dealing with the adequacy of power supply. As electric industry restructuring has begun to break apart the traditional model of the vertically integrated utility, the responsibility for maintaining the adequacy of the power supply is moving toward market mechanisms. Though there may not be specific entities entrusted to plan for adequate resources, there exists a need to assess whether projected resources will be sufficient to reliably meet demand. Such information will allow regulators and policy makers to anticipate potential shortfalls so that determinations can be made as to whether impediments or insufficient incentives exist in the market. It is not the intent of an adequacy assessment to replace the market, create sanctionable criteria or anticipate future energy prices. Its purpose is to project whether enough resources exist, at any price, to meet load and possible reserves while considering the transmission transfer capabilities of major paths. Such an assessment is required to comply with the NERC Planning Standards. These standards require that each region perform a regional assessment of existing and planned (forecast) adequacy of the bulk electric system. It is recognized that it is impossible to provide 100% adequacy of power supply. It is the purpose of this document to establish a uniform policy for assessing the adequacy of installed and planned resources within the WECC region for the purposes of reporting within the Council, and to outside agencies. The assessments shall cover a period encompassing the next 5 years.

ASSESSMENT METHODOLOGY The Power Supply Assessment Methodology shall be developed and maintained by the Reliability Subcommittee. Adequacy of supply may be defined and measured in terms of generating reserve margins and transmission limitations between load and resource areas and/or based on probabilistic methods. Appropriate technical tools shall be developed and utilized in conducting the assessments. The assessments shall account for diversity of load and generation, and account for transmission constraints between load and resource areas. DATA REQUIREMENTS To aid WECC in assessing resource adequacy, the following information shall be provided by the WECC members:

Load Forecasts

• Electricity demand and energy forecasts, including uncertainties

• Variations due to weather

• Variations due to other factors affecting forecasts

Demand Side Management (DSM) Programs

• Existing and planned demand-side management programs

• Direct controlled interruptible loads

• Aggregate effects of multiple DSM programs

Resource Information

• Supply-side resource characteristics, including uncertainties

• Consistent generator unit ratings, including seasonal variations and environmental considerations affecting hydro and thermal units

• Availability of generating units • Fuel type

Transmission Information

• Capabilities, availability of transmission capacity, and other uncertainties

REPORTING OF POWER SUPPLY ADEQUACY The assessment of generating reserve margins and transmission limitations between load and resource areas as well as probabilities of supplying expected load levels, accounting for uncertainties, shall be developed and the results reported on a seasonal basis. The assessment shall be consistent with the requirement for maintaining operating reserves as defined in the WECC Minimum Operating Reliability Criteria and NERC Operating Policies.

Approved by Reliability Subcommittee June 16, 2000 Approved by Planning Coordination Committee June 30, 2000 Approved by Board of Trustees August 8, 2000 Revised April 18, 2002

WESTERN ELECTRICITY COORDINATING COUNCIL

MINIMUM OPERATING RELIABILITY CRITERIA PART III

Western Electricity Coordinating Council

WESTERN ELECTRICITY COORDINATING COUNCIL

MINIMUM OPERATING RELIABILITY CRITERIA

Revised April 6, 2005

WESTERN ELECTRICITY COORDINATING COUNCIL

MINIMUM OPERATING RELIABILITY CRITERIA

TABLE OF CONTENTS

Section Page

1. GENERATION CONTROL AND PERFORMANCE..................................................2

2. TRANSMISSION..........................................................................................................8

3. INTERCHANGE .........................................................................................................11

4. SYSTEM COORDINATION ......................................................................................13

5. EMERGENCY OPERATIONS...................................................................................16

6. OPERATIONS PLANNING .......................................................................................21

7. TELECOMMUNICATIONS.......................................................................................25

8. OPERATING PERSONNEL AND TRAINING.........................................................25

WESTERN ELECTRICITY COORDINATING COUNCIL

MINIMUM OPERATING RELIABILITY CRITERIA INTRODUCTION The reliable operation of the Western Interconnection requires that all entities comply with the Western Electricity Coordinating Council (WECC) Minimum Operating Reliability Criteria (hereafter referred to as MORC). The MORC shall apply to system operation under all conditions, even when facilities required for secure and reliable operation have been delayed or forced out of service. On a continuing basis, the North American Electric Reliability Council (NERC), through its Operating Committee, establishes, reviews, and updates operating criteria to be followed by individual entities, pools, coordinated areas and reliability councils. All entities, WECC members and nonmembers, shall operate in accordance with the NERC or WECC Reliability Criteria, whichever is more specific or stringent. In addition to complying with the MORC, all entities shall comply with all WECC Operating Policies and Procedures which are included in the WECC Operations Committee Handbook. The WECC shall periodically review and revise MORC in accordance with the guidelines set forth in the WECC Reliability Criteria Part V – Process for Developing and Approving WECC Standards. NERC has identified control areas as the primary entities responsible for ensuring the secure and reliable operation of the interconnected power system. Secure and reliable operation can only result from all entities complying with a consistent set of operating criteria. To this end it is imperative for all control areas in the Western Interconnection to be members of the WECC. Entities such as Independent System Operators and Area Reliability Coordinators may assume some of the responsibilities that control areas have traditionally held. It is also imperative that these entities be WECC members and comply with all operating reliability criteria which apply to control areas. The MORC and all WECC Operating Policies and Procedures apply to all entities unless expressly stated as applying only to a particular entity. It is imperative that all entities equitably share the various responsibilities to maintain reliability. Examples of equitably sharing reliability responsibilities include, but are not limited to:

• proper coordination and communication of interchange schedules, • participation in coordinated underfrequency load shedding programs, • participation in the unscheduled flow mitigation plan, • providing appropriate levels of power system stabilizers, and • maintaining appropriate governor droop settings.

The MORC is divided into sections corresponding to the NERC Policies. Also included are the coordination requirements necessary to achieve the objectives set forth in these Criteria. It is emphasized that these are minimum criteria related to operating reliability or procedures

which are necessary for the secure and reliable operation of the interconnected power system. More specific and more stringent operating reliability criteria may be developed by each individual entity, pool, and/or coordinated area within the WECC. Section 1 - Generation Control and Performance

All generation shall be operated to achieve the highest practical degree of service reliability. Appropriate remedial action will be taken promptly to eliminate any abnormal conditions which jeopardize secure and reliable operation.

A. Operating Reserve

The reliable operation of the interconnected power system requires that adequate generating capacity be available at all times to maintain scheduled frequency and avoid loss of firm load following transmission or generation contingencies. This generating capacity is necessary to:

• supply requirements for load variations.

• replace generating capacity and energy lost due to forced outages of generation or transmission equipment.

• meet on-demand obligations.

• replace energy lost due to curtailment of interruptible imports.

1. Minimum operating reserve. Each control area shall maintain minimum operating reserve which is the sum of the following:

(a) Regulating reserve. Sufficient spinning reserve, immediately responsive to automatic generation control (AGC) to provide sufficient regulating margin to allow the control area to meet NERC’s Control Performance Criteria.

Plus (b) Contingency reserve. An amount of spinning and nonspinning reserve, sufficient to meet the Disturbance Control Standard as defined in 1.E.2(a). This Contingency Reserve shall be at least the greater of:

(1) The loss of generating capacity due to forced outages of generation or transmission equipment that would result from the most severe single contingency (at least half of which must be spinning reserve); or

(2) The sum of five percent of the load responsibility served by hydro generation and seven percent of the load responsibility served by thermal generation (at least half of which must be spinning reserve).

For generation-based reserves, only the amount of unloaded generating capacity that can be loaded within ten minutes of notification can be considered as reserve.

Plus (c) Additional reserve for interruptible imports. An amount of reserve, which can be made effective within ten minutes following notification, equal to interruptible imports.

Plus (d) Additional reserve for on-demand obligations. An amount of reserve, which can be made effective within ten minutes following notification, equal to on-demand obligations to other entities or control areas.

2. Acceptable types of nonspinning reserve. The nonspinning reserve obligations identified in A.1.b, A.1.c, and A.1.d, if any, can be met by use of the following:

(a) load which can be interrupted within 10 minutes of notification

(b) interruptible exports

(d) spinning reserve in excess of requirements in A.1.a and A.1.b

(e) off-line generation which qualifies as nonspinning reserve (see definition)

3. Knowledge of operating reserve. Operating reserves shall be calculated such that the amount available which can be fully activated in the next ten minutes will be known at all times.

4. Restoration of operating reserve. After the occurrence of any event necessitating the use of operating reserve, that reserve shall be restored as promptly as practicable. The time taken to restore reserves shall not exceed 60 minutes.

5. Analysis of islanding potential. Each entity or coordinated group of entities shall analyze its potential for islanding in total or in part from interconnected resources at least every three years and shall maintain appropriate additional operating reserve for such contingencies or, if such is impractical, its load and generation shall be balanced by other appropriate measures.

6. Sharing operating reserves. Under written agreement, the operating reserve requirements of two or more control areas may be combined or shared, providing that such combination, considered as a single control area, meets the obligations of paragraph A.1. Similarly, arrangements may be made whereby one control area supplies a portion of another’s operating reserve, provided that such capacity can be made available in such a manner that both meet the requirements of paragraph A.1. A firm transmission path must be available and reserved for the transmission of these operating reserves from the control area supplying the reserves to the control area calling on them.

7. Operating reserve distribution. Prudent operating judgment shall be exercised in distributing operating reserve, taking into account effective use of capacity in an emergency, time required to be effective, transmission

limitations, and local area requirements. Spinning reserve should be distributed to maximize the effectiveness of governor action.

8. Review of contingencies. To determine the amount of operating reserve required, contingencies shall be frequently reviewed and the most severe contingency designated.

B. Automatic Generation Control

Each control area shall operate sufficient generating capacity under automatic control to meet its obligation to continuously balance its generation and interchange schedules to its load. It shall also provide its proper contribution to Interconnection frequency regulation.

1. Inclusion in control area. Each entity operating transmission, generation, or distribution facilities shall either operate a control area or make arrangements to be included in a control area operated by another entity. All generation, transmission, and load operating within the Western Interconnection shall be included within the metered boundaries of a WECC control area. Control areas are ultimately responsible for ensuring that the total generation is properly matched to total load in the Interconnection.

2. AGC. Prudent operating judgment shall be exercised in distributing control among generating units. AGC shall remain in operation as much of the time as possible. As described in the WECC Guidelines for Suspending Automatic Generation Control in the WECC Operations Committee Handbook, AGC suspension should be considered when AGC equipment has failed or if system conditions could be worsened by AGC.

3. Familiarity with AGC equipment. Control center operating personnel must be thoroughly familiar with AGC equipment and be trained to take necessary corrective action when equipment fails or misoperates. If primary AGC has become inoperative, backup AGC or manual control shall be used to adjust generation to maintain schedules.

4. Data scan rates for ACE. It is recommended that the periodicity of data acquisition for and calculation of ACE should be no greater than four seconds.

C. Frequency Response and Bias

1. Frequency bias. The frequency bias shall be set as close as possible to the control area’s natural frequency response characteristic. Refer to NERC Policy 1C for determining frequency bias setting methodologies.

a. Frequency bias setting for control areas with native load. In no case shall the annual fixed frequency bias or the monthly average variable frequency bias be set at a value of less than 1% of the estimated control area annual peak load per 0.1 Hz change in frequency.

b. Frequency bias setting for generation-only control areas. At a minimum, the annual fixed frequency bias or the monthly average variable frequency bias shall be set at a value of the total generator droop setting from WECC MORC Section 1.C.2 per 0.1 hertz change in frequency.

2. Governors. To provide an equitable and coordinated system response to load/generation imbalances, governor droop shall be set at 5%. Governors shall not be operated with excessive deadbands, and governors shall not be blocked unless required by regulatory mandates.

3. Tie-line bias. Each control area shall operate its AGC on tie-line frequency bias mode, unless such operation is adverse to system or Interconnection reliability.

D. Time Control

1. Time error. Control areas shall assist in maintaining frequency at or as near 60.0 Hz as possible and shall cooperate in making any necessary time corrections per the WECC Procedure for Time Error Control. The amount of continuous time error contribution is a function of control area time error bias, inadvertent interchange accumulation, and the time error.

2. Maintain standards for frequency offset. Control areas shall cooperate in maintaining standards established by the NERC Operating Committee for frequency offset to make time corrections manually.

3. Time error correction notice and commencement. Time error corrections shall start and end on the hour or half hour, and notice shall be given at least twenty minutes before the time error correction is to start or stop. Time error corrections shall be made at the same rate by all control areas.

4. Calibration of time and frequency devices. Each control area shall at least annually check and calibrate its time error and frequency devices against a common reference.

E. Control Performance

1. Continuous monitoring. Each control area shall monitor its control performance on a continuous basis against two Standards: CPS1 and CPS2.

(a) Control performance standard (CPS1). Over a year, the average of the clock-minute averages of a control area’s ACE divided by -10β (β is control area frequency bias) times the corresponding clock-minute averages of Interconnection’s frequency error shall be less than a specific limit. This limit, ε, is a constant derived from a targeted frequency bound reviewed and set as necessary by the NERC Performance Subcommittee.

(b) Control performance standard (CPS2). The average ACE for each of the six ten-minute periods during the hour (i.e., for the ten-minute periods ending at 10, 20, 30, 40, 50, and 60 minutes past the hour) must be within specific limits, referred to as L10. See NERC’s Performance Standard Training Document, Section B.1.1.2 for the methods for calculating L10.

(c) Control performance standard (CPS) compliance. Each control area shall achieve CPS1 compliance of 100% and achieve CPS2 compliance of 90%.

2. Disturbance conditions. In addition to CPS1 and CPS2, the Disturbance Control Standard shall be used by each control area or reserve sharing group to monitor control performance during recovery from disturbance conditions (see the Performance Standard Training Document, Section B.2):

(a) Disturbance Control Standard. Following the start of a disturbance, the ACE must return either to zero or to its pre-disturbance level within the time specified in the Disturbance Control Standard currently in effect in NERC Policy 1.

(b) Disturbance control standard compliance. Each control area or reserve sharing group shall meet the Disturbance Control Standard (DCS) 100% of the time for reportable disturbances.

(c) Reportable disturbance reporting threshold. Each control area or reserve sharing group shall include events that cause its Area Control Error (ACE) to change by at least 35% of the maximum loss generation that would result from a single contingency.

(d) Average percent recovery. For each reportable disturbance, the control area(s) with a MW loss or participating in the response, such as through operating reserve obligations or through a reserve sharing group, shall calculate an Average Percent Recovery. A copy of the control area’s calculations, ACE chart, and Net Tie Deviation from Schedule chart shall be submitted to the NERC Regional Performance Subcommittee representative not later than 10 calendar days after the reportable disturbance.

(e) Contingency reserve adjustment factor. The WECC Performance Work Group (PWG) shall determine the Contingency Reserve Adjustment Factor for each control area no later than April 20, July 20, September 20, and January 20 for the previous quarter. The local PWG representatives shall allocate the factor among control areas that are members of reserve sharing groups according to the allocation methods developed by the group.

(f) Operating reserve for control areas and reserve sharing groups. Minimum Operating Reserve shall be increased by the Contingency Reserve Adjustment Factor. The WECC Performance Work Group shall monitor the compliance of each control area and reserve sharing group for carrying the minimum required operating reserve.

3. ACE values. The ACE used to determine compliance to the Control Performance Standards shall reflect its actual value, and exclude short excursions due to transient telemetering problems or other influences such as control algorithm action.

F. Inadvertent Interchange

1. Hourly verification. Each control area shall, through hourly schedule verification and the use of reliable metering equipment, accurately account for inadvertent interchange.

2. Common metering. Each control area interconnection point shall be equipped with a common kWh meter, with readings provided hourly at the control centers of both areas.

3. Including all interconnections. All interconnections shall be included in inadvertent interchange accounting. Interchange served through jointly owned facilities and interchange with borderline customers shall be properly taken into account.

G. Control Surveys

1. Survey purpose. Periodic surveys of the control performance of the control areas shall be conducted. These surveys reveal control equipment malfunctions, telemetering errors, improper frequency bias settings, scheduling errors, inadequate generation under automatic control, general control performance deficiencies, or other factors contributing to inadequate control performance.

2. Surveys. The control areas in the Western Interconnection shall perform each of the following surveys, as described in the NERC Control Performance Criteria Training Document, when called for by the NERC Performance Subcommittee:

(a) AIE survey. Area Interchange Error survey to determine the control area’s interchange error(s) due to equipment failures, improper scheduling operations, or improper AGC performance.

(b) FRC survey. Area Frequency Response Characteristic survey to determine the control area’s response to changes in system frequency.

(c) CPC survey. Control Performance Criteria survey to monitor the control area’s control performance during normal and disturbance situations.

H. Control and Monitoring Equipment

1. Tie line bias control equipment. Each control area shall use accurate and reliable automatic tie line bias control equipment as a means of continuously balancing actual net interchange with scheduled net interchange, plus or minus its frequency bias obligation and automatic time error correction. The power flow and ACE signals that are transmitted for regulation service shall not be filtered prior to transmission except for anti-aliasing filtering of tie lines.

2. Tie flows in ACE calculation. To achieve accurate control, each control area shall include all of its interconnecting ties in its ACE calculation. Common interchange metering equipment at agreed upon terminals shall be used by adjacent control areas.

3. Control checks made each hour. Actual interchange shall be verified each hour by each control area using tie line kWh meters to determine regulating performance. Adjacent control areas shall use the same MWh value for each common interchange point. Control settings shall be adjusted to compensate for any equipment error until equipment malfunction can be corrected.

I. Backup Power Supply

Under emergency conditions, adequate and reliable emergency or backup power supply must be available to provide for generating equipment protection and continuous operation of those facilities required for restoration of the system to normal operation.

1. Safe shut-down power. Emergency or auxiliary power supply shall be provided for the safe shutdown of thermal generating units when completely isolated from a power source.

2. Reliable start-up power. A reliable and adequate source of start-up power for generating units shall be provided. Where sources are remote from the generating unit, standing instructions shall be issued to expedite start up.

3. Black start capability for critical generating units. All control areas must identify critical generating units and ensure provision of “black start” capability for these units if appropriate arrangements have not been made to receive off-system power for the purpose of system restoration.

4. Testing. Emergency or backup power supplies shall be periodically tested to ensure their availability and performance.

Section 2 - Transmission

The interconnected power system shall be operated to achieve the highest practical degree of service reliability. Appropriate remedial action shall be taken promptly to eliminate any abnormal conditions which jeopardize secure and reliable operation.

A. Transmission Operations

1. Basic criteria. The interconnected power system shall be operated at all times so that general system instability, uncontrolled separation, cascading outages, or voltage collapse will not occur as a result of any single contingency or multiple contingencies of sufficiently high likelihood (as defined below). Entities must ensure this criteria is met under all system conditions including equipment out of service, equipment derates or modifications, unusual loads and resource patterns, and abnormal power flow conditions. A single contingency means the loss of a single system element, however, the outage of multiple system elements should be treated as a single contingency if caused by a single event of sufficiently high likelihood. When experience proves that an outage involving multiple system elements, AC or DC, occurs more than once during the previous three years and causes, on other systems, loss of load, loss of generation rated greater than 100 MW or cascading outages, it shall be treated as a single contingency.

When it is agreed that a disturbance on specific facilities occurs more often than should be reasonably expected and results in an undue burden on the transmission system, the owners of the facilities shall take measures to reduce the frequency of occurrence of the disturbance, and cooperate with other entities in taking measures to reduce the effects of such disturbance.

During disturbances, the primary objective is to minimize the magnitude and duration of load interruptions for the Western Interconnections. This may require load interruptions in local areas or controlled separation to avoid greater impacts to the Interconnection or to expedite restoration.

It is undesirable for the loss of load to exceed the amount of load designed to be tripped. This applies to all levels of system underfrequency load shedding programs, undervoltage load tripping schemes or other controlled remedial actions. It applies whether the initiating disturbance occurs within or outside the affected system. Entities may be required to establish maximum import levels to meet these criteria. The necessary operating procedures, equipment, and remedial action schemes shall be in place to prevent unplanned or uncontrolled loss of load or total system shutdown.

2. Joint reliability procedures. Where specific transmission issues have been identified, those entities affected by and those entities contributing to the problem shall develop joint procedures for maintaining reliability.

3. Phase-shifting transformers and other flow altering facilities. Phase shifting transformers or other facilities, when used to alter power flow through the interconnected power system, shall be operated to control the actual power flow within the limits of the scheduled power flow and the unaltered power flow. In meeting the criteria, a tolerance of two taps on phase shifting transformers and one discrete increment on other noncontinuous controllable devices is permissible provided no other operating criteria are violated. Such power flow altering facilities may be operated to some other criteria provided agreement is reached among the affected parties.

4. Protective relay reliability. Relays that have misoperated or are suspected of improper operation shall be promptly removed from service until repaired or correct operation is verified.

B. Voltage and Reactive Control

1. Maintaining service. To ensure secure and reliable operation of the interconnected power system, reactive supply and reactive generation shall be properly controlled, adequate reactive reserves shall be provided, and adequate transmission system voltages shall be maintained.

2. Providing reactive requirements. Each entity shall provide for the supply of its reactive requirements, including appropriate reactive reserves, and its share of the reactive requirements to support power transfers on interconnecting transmission circuits.

3. Coordination. Operating entities shall coordinate the use of voltage control equipment to maintain transmission voltages and reactive flows at optimum

levels for system stability within the operating range of electrical equipment. Operating strategies for distribution capacitors and other reactive control equipment shall be coordinated with transmission system requirements.

4. Transmission lines. Transmission lines should be kept in service as much as possible. They may be removed from service for voltage control only after studies indicate that system reliability will not be degraded below acceptable levels. The entity responsible for operating such transmission line(s) shall promptly make notification according to the WECC Procedure for Coordination of Scheduled Outages and Notification of Forced Outages when removing such facilities from and returning them back to service.

5. Generators. Generating units 10 MVA and larger shall be equipped with automatic voltage control equipment. All generating units with automatic voltage control equipment shall normally be operated in voltage control mode. These generating units shall not be operated in other control modes (e.g., constant power factor control) unless authorized to do so by the host control area. The control mode of generating units shall be accurately represented in operating studies.

6. Automatic voltage control equipment. Automatic voltage control equipment on generating units, synchronous condensers, and static var compensators shall be kept in service to the maximum extent possible with outages coordinated to minimize the number out of service at any one time. Such voltage control equipment shall operate at voltages specified by the host control area operator.

7. Power system stabilizers. Power System Stabilizers on generators shall be kept in service to the maximum extent possible and shall be properly tuned in accordance with WECC requirements.

8. Reactive reserves. Operating entities shall ensure that reactive reserves are adequate to maintain minimum acceptable voltage limits under facility outage conditions. Reactive reserves required for acceptable response to contingencies shall be automatically applied when contingencies occur. Operation of static and dynamic reactive devices shall be coordinated such that static devices are switched in or out of service so that the maximum reactive reserves are maintained on generators, synchronous condensers and other dynamic reactive devices.

9. Undervoltage load shedding. Operating entities shall assess the need for and install undervoltage load shedding as required to augment other reactive reserves to protect against voltage collapse and ensure system reliability performance criteria as specified in the WECC Disturbance-Performance Table of Allowable Effect on Other Systems are met during all internal and external outage conditions. The operator shall have written authority to manually shed additional load if necessary to maintain acceptable voltages and/or sufficient reactive margin to protect against voltage collapse.

10. Switchable devices. Devices frequently switched to regulate transmission voltage and reactive flow shall be switchable without de-energizing other facilities.

11. HVDC. Entities with HVDC transmission facilities should use the reactive capabilities of converter terminal equipment for voltage control.

Section 3 - Interchange

To ensure the secure and reliable operation of the interconnected power system, all entities involved in interchange scheduling shall coordinate and communicate information concerning schedules and schedule changes accurately and timely as detailed in the WECC Scheduling Procedures for All Entities Involved in Interchange Scheduling.

A. Interchange

1. Net schedules. The net schedule on any control area to control area interconnection or transfer path within a control area shall not exceed the total transfer capability of the transmission facilities.

2. Transfer capability. Transmission providers or control areas shall determine normal total transfer capability limits for the delivery and receipt of scheduled interchange. The determination of such total transfer capability limits shall, as far as practicable, take into consideration the effect of power flows through other parallel systems or control areas under both normal operating conditions and with a single contingency outage of the most critical facility.

3. Schedule confirmation and implementation. All scheduled transactions shall be confirmed and implemented between or among the control areas involved in such transactions. “Control areas involved” means the control area where the schedule originates, the control area(s) providing transmission service for the transaction, and the control area where the scheduled energy is delivered. If a schedule cannot be confirmed it shall not be implemented.

4. Schedule verification. Each Control Area is responsible to have the net scheduled interchange verified with all adjacent Control Areas on an hourly preschedule and real-time basis. This verification may be accomplished through a designated agent. Real-time verification shall take place prior to the start of the ramp.

5. Schedule changes. Schedule changes must be coordinated between control areas to ensure that the schedule changes will be executed by all control areas at the same time, in the same amount and at the same rate.

6. Type of transaction. Parties providing and receiving the scheduled energy shall agree upon the type of transaction being implemented (firm or interruptible) and the control area(s) and other parties providing the operating reserve for the transaction, and shall make this information available to all control areas involved in the transaction.

7. Information sharing. Control areas, pools, coordinated areas or reliability councils shall develop procedures to disseminate information on schedules which may have an adverse effect on other control areas not involved in making the scheduled power transfer.

8. Unscheduled flow. Unscheduled flow is an inherent characteristic of interconnected AC power systems and the mere presence of unscheduled flow on circuits other than those of the scheduled transmission path is not necessarily an indication of a problem in planning or in scheduling practices. WECC transmission paths experiencing significant curtailments as a result of unscheduled flow may be qualified for unscheduled flow relief under the WECC Unscheduled Flow Reduction Procedure. All personnel involved in interchange scheduling shall be trained and fully competent in implementing the WECC Unscheduled Flow Reduction Procedure.

The WECC planning process and the Unscheduled Flow Reduction Procedure are designed to minimize impact of unscheduled flow for normal system configurations. During abnormal system configurations such as during the restoration period following a major system disturbance, consideration shall be given to the unscheduled flow effects created by schedules and scheduled transmission paths and the reliability coordinator(s) shall ensure that all schedules are arranged such that the effect of unscheduled flow does not cause transfer capability limits to be exceeded on other transmission paths.

It is unacceptable to rely on opposing unscheduled flow to keep actual flows within the path total transfer capability regardless of whether the path is a transmission element internal to a control area or whether the path is a control area to control area interconnection.

B. Transfer Capability Limit Criteria

The total transfer capability limit is the maximum amount of actual power that can be transferred over direct or parallel transmission elements comprising:

• An interconnection from one control area to another control area; or

• A transfer path within a control area.

The net schedule and prevailing actual power flowing over an interconnection or transfer path within a control area shall not exceed the total transfer capability limit on the interconnection or transfer path.

1. Operating limits. No elements within the interconnection shall be scheduled above continuous operating limits. An element is defined as any generating unit, transmission line, transformer, bus, or piece of electrical equipment involved in the transfer of power within an interconnection. At all times the interconnected system shall be operated so neither the net scheduled or actual power transferred over an interconnection or transfer path shall exceed the total transfer capability of that interconnection or transfer path. If the limit is exceeded, immediate action shall be taken to reduce actual flow to within transfer capability limits within 20 minutes for stability limitations and within 30 minutes for thermal limitations.

2. Stability. The interconnected power system shall remain stable upon loss of any one single element without system cascading that could result in the successive loss of additional elements. The system voltages shall be within acceptable limits defined in the NERC/WECC Planning Standards. If a single event could cause loss of multiple elements, these shall be considered in lieu of a single element outage. This could occur in exceptional cases such as two lines on the same right-of-way next to an airport. In either case, loss of either single or multiple elements should not cause uncontrolled, widespread collapse of the interconnected power system.

3. System contingency response. Following the outage and before adjustments can be made:

(a) No remaining element shall exceed its short-time emergency rating.

(b) The steady-state system voltages shall be within emergency limits.

The limiting event shall be determined by conducting power flow and stability studies while simulating various operating conditions. These studies shall be updated as system configurations introduce significant changes in the interconnection.

Section 4 - System Coordination

A high degree of coordination is essential within and between the entities, control areas, pools and coordinated areas of the WECC in all phases of operation which can affect the reliability of the interconnected power system.

This section sets forth operating items that require coordination to make certain that the minimum operating reliability criteria contained herein can be realized by the interconnected power system.

A. Monitoring System Conditions

Coordination and communication in the following areas is essential for secure and reliable operation of the interconnected power system.

1. System conditions. Loads, generation, transmission line and bulk power transformer loading, voltage, and frequency shall be monitored as required to determine if system operation is within known safe limits under both normal and emergency situations.

2. Deviations. The use of automatic equipment to bring immediate attention to important deviations in system operating conditions and to indicate or initiate corrective action shall be implemented.

3. Remedial action scheme status alarms. Alarms shall be provided to alert operating personnel regarding the status of remedial action schemes which are under their direct control and impact the reliability and security of interconnected power system operation.

4. Sharing operational information. All entities shall, by mutual agreement, provide essential and timely operational information regarding their system

(e.g., line flows, generator status, net interchange schedules at tie points, etc.) to all affected transmission providers and control areas.

5. Voltage collapse. Information regarding system problems that could lead to voltage collapse shall be disseminated and operation to alleviate the effects of such severe conditions shall be coordinated.

B. Coordination with Other Entities

1. Procedures. Procedures shall be in place for the effective transfer of operating information between control areas, entities, and coordinated groups of entities as necessary to maintain interconnected power system reliability.

2. Switching operation. The opening or closing of interconnections between control areas, and the opening or closing of any lines internal to control areas which may affect the operation of the interconnected power system under normal and emergency conditions must be fully coordinated.

3. Voltage and reactive flows. Control areas shall coordinate the control of voltage levels and reactive flows during normal and emergency conditions. All operating entities shall assist with their control area’s coordination efforts.

4. Load shedding and restoration. The shedding and restoration of loads in emergencies must be coordinated as described in detail in Sections 5.D. and 6.C.

5. Automatic actions. Any automatic controlled islanding and automatic generator tripping which is necessary to maintain interconnected power system stability under emergency conditions shall be coordinated. All automatic remedial actions (automatic bypass of series compensation, phase shifter runback, opening of lines or transformers, load tripping, etc.) which may impact the interconnected power system, shall be coordinated.

6. Interconnection capabilities. Information regarding the operating capabilities of interconnecting facilities between operating entities or control areas shall be exchanged routinely and all operating entities shall coordinate establishment of the operating limitations of these facilities under normal and emergency conditions.

7. Plans and forecasts. Information regarding short-term load forecasts, generating capabilities, and schedules of additions or changes in system facilities that could affect interconnected operation shall be routinely disseminated.

8. System characteristics. Information regarding system electrical characteristics that affect the operation of the interconnected system, including any significant changes which result from the addition of facilities or modification of existing facilities, shall be routinely disseminated.

9. Operating reserve. Information regarding operating reserve policies and procedures shall be routinely disseminated.

10. Abnormal operating conditions. Operating entities forced to operate in such a way that a single contingency could result in general system instability, uncontrolled separation, cascading outages, or voltage collapse, shall promptly notify WECC and other affected operating entities via the WECC Communication System.

11. Notification of system emergencies. In the event of system emergencies involving loss of any element(s), all affected entities and control areas shall be notified of the extent of the outage and estimated time of restoration. Preliminary emergency outage notification shall be provided via the WECC Communication System as quickly as possible. Restoration information, if not available immediately, shall be provided as soon as practicable.

12. Notification of noncompliance. If an operating entity is not able to comply with the condition and term of a particular criterion, it must notify the host control area. The control area operator will notify the WECC who will report the noncompliance to the NERC Operating Committee.

C. Maintenance Coordination

1. Sharing information. The security and reliability of the interconnected power system depends upon periodic inspection and adequate maintenance of generators, transmission lines and associated equipment, control equipment, communication equipment, relaying equipment and other system facilities. Entities and coordinated groups of entities shall establish procedures and responsibility for disseminating information on scheduled outages and for coordinating scheduled outages of major facilities which affect the security and reliability of the interconnected power system.

D. System Protection Coordination

Reliable and adequate relaying must be provided to protect and permit maximum utilization of generation, transmission and other system facilities.

1. Coordination. Information regarding protective relay systems affecting interconnected operation shall be routinely disseminated and the settings of such relays shall be coordinated with the affected entities.

2. Reviewing settings. Relay applications and settings shall be reviewed periodically and adjustments made as needed to meet system requirements.

3. Testing. Each operating entity shall periodically test protective relay systems and remedial action schemes which impact the security and reliability of interconnected power system operation.

Section 5 - Emergency Operations

Even though precautionary measures have been developed and utilized, and extensive protective equipment installed, emergencies of varying magnitude do occur on the interconnected power system. These emergencies may be minor in nature and require small, real-time system adjustments, or they may be major and require fast, preplanned action to avoid the cascading loss of generation or transmission lines, uncontrolled separation, and interruption of customer service. All entities are expected to cooperate and take appropriate action to mitigate the severity or extent of any foreseeable system disturbance. Those operating criteria relating to emergency operation are set forth in this section.

A. Emergency Operating Philosophy

During an emergency condition, the security and reliability of the interconnected power system are threatened; therefore, immediate steps must be taken to provide relief. The following operating philosophy shall be observed:

1. Corrective action. The entity(ies) experiencing the emergency condition shall take immediate steps to relieve the condition by adjusting generation, changing schedules between control areas, and initiating relief measures including manual or automatic load shedding (if required) to relieve overloading or imminent voltage collapse. ACE shall be returned to zero or to its predisturbance value within the time specified in the Disturbance Control Standard following the start of a disturbance.

2. Written authority. Dispatching personnel shall have full responsibility and written authority to implement the emergency procedures listed in 5.A.1. above.

3. Reestablishing reserves. Operating entities or control areas shall immediately take steps to reestablish reserves to protect themselves and ensure that loss of any subsequent element will not violate any operating limits. The time taken to restore resource operating reserves shall not exceed 60 minutes.

4. Notifying other affected entities. In the event of system emergencies involving loss of any element(s), all affected entities and control areas shall be notified of the extent of the outage and estimated time of restoration. Preliminary emergency outage notification shall be provided via the WECC Communication System as quickly as possible. Restoration information, if not available immediately, shall be provided as soon as practicable.

5. AGC. AGC shall remain in service as long as its action continues to be beneficial. If AGC is out of service, manual control shall be used to adjust generation. AGC shall be returned to service as soon as practicable.

6. Prompt restoration. The affected entity(ies) and control area(s) shall restore the interconnected power system to a secure and reliable state as soon as possible.

7. Zeroing schedules. Energy schedules on a transmission path shall be promptly reduced to zero following an outage of the path unless a backup transmission path has been pre-arranged. If a system disturbance results in system islanding,

all energy schedules across open paths between islands shall be immediately reduced to zero unless doing so would prolong frequency recovery.

8. Emergency total transfer capability limits. Emergency total transfer capability limits shall be established which will permit maintaining stability with voltage levels, transmission line loading and equipment loading within their respective emergency limits in the event another contingency occurs.

9. Adjustments following loss of resources. Following the loss of a resource within a control area, scheduled and actual interchange shall be re-balanced within the time specified in the Disturbance Control Standard following the loss of a resource within a control area. Following the loss of a remote resource or curtailment of other interchange being scheduled into a control area with no backup provisions, the energy loss shall be immediately reflected in the control area’s ACE and corrected within the time specified in the Disturbance Control Standard.

B. Coordination with Other Entities

1. Emergency outages. Information regarding emergency outages of facilities, the time frame for restoration of these facilities, and the actions taken to mitigate the effects of the outages must be exchanged promptly with other affected entities.

2. Voltage collapse. Information regarding problems that could lead to voltage collapse shall be disseminated to other affected entities. Operation to alleviate the effects of such severe conditions shall be coordinated with all affected entities.

3. Other affecting conditions. Information regarding violent weather disturbances or other disastrous conditions which could affect the security and reliability of the interconnected power system shall be disseminated to all affected entities. Operation to alleviate the effects of such severe conditions shall be coordinated with all affected entities.

4. Single contingency exposure. All affected entities shall be notified promptly via the WECC Communication System by any entity forced to operate in such a way that a single contingency outage could result in general system instability, uncontrolled separation, cascading outages, or voltage collapse. Entities not connected to the WECC Communication System shall make this notification through their host control area.

5. Emergency support personnel. All control areas shall arrange for technical and management support personnel to be available 24 hours per day to provide coordination support in the event of system disturbances or emergency conditions. These personnel shall be on call to coordinate collecting and sharing of information. Each control area shall develop procedures in coordination with the Reliability Coordinators and the WECC office to fulfill this support responsibility. The Reliability Coordinators shall expedite communication of appropriate information to the WECC office during system disturbances and emergency operating conditions to enable the WECC office to

coordinate the reporting of information pertaining to the entire western region to federal agencies, regulatory bodies, and the news media in a timely manner. Management support personnel shall maintain close and timely communication with the WECC office during extreme emergency conditions or system disturbances of widespread significance in the Western Interconnection.

C. Insufficient Generating Capacity

1. Capacity or energy shortages

(a) A control area experiencing capacity or energy shortages after exhausting all possible assistance from entities within the control area shall immediately notify its Reliability Coordinator and request assistance from adjacent control areas or entities. Neighboring control areas shall be notified as to the amount of the capacity or energy shortages. Neighboring control areas shall make every effort to provide all available assistance.

(b) If inadequate relief is obtained from (a) above, then, control area(s) shall initiate relief measures as required, up to and including shedding load, to maintain reserves as specified in Section 1.A.

2. Deficient Resource Loss.

Following a resources loss greater than MSSC, or after failing to meet DCS, a control area shall immediately take the necessary steps to return ACE to zero:

• load all available generating capacity, and

• utilize all operating reserve, and

• interrupt all interruptible load and interruptible exports, and

• utilize fully all emergency assistance from other control areas, and

• shed load.

3. Manual load shedding. Through written standing orders and instructions the system dispatchers shall be given clear authority to implement manual load shedding without consultation whenever, in their judgment, such immediate action is necessary to protect the reliability and integrity of the system. Manual load shedding may also be required to restore system frequency which has stabilized below 60 Hz or to avoid an imminent separation which would produce a severe deficiency of power supply in the affected area. Upon system separation or islanding, manual load shedding may be required to restore system frequency which has stabilized below 60 Hz.

D. Restoration

Following a major disturbance which may require load shedding, sectionalizing, or generator tripping, immediate steps must be taken to return the system to normal.

Extreme care must be exercised to avoid prolonging or compounding the emergency. While each disturbance will be different and may require different dispatcher action, the criteria set forth in the following subsections will provide the general guidelines to

be observed. It is imperative that dispatchers maintain close coordination with neighboring dispatchers during restoration as follows:

1. Extent of island. Determine the extent of the islanded area or areas. Take any necessary action to restore area frequency to normal, including adjusting generation, shedding load and synchronizing available generation with the area.

The following is a checklist of items to be communicated to determine any action required prior to reconnecting systems following a major disturbance:

(a) Determine the condition of your own system:

(1) Separation points

(2) Overloaded ties

(3) Power flows

(4) Condition of generation

(5) Load shed

(b) Contact immediate neighbors to determine their condition:

(1) Effect of the disturbance on them.

(2) Their separation points.

(3) Can a tie be made to them which will help your system or will help their system?

(4) The amount of their or your system to be paralleled or picked up.

(5) The relative speeds of the two systems and the potential impacts of closing the tie.

(6) Overload conditions or potential overloads to be made worse or better by the tie.

(7) The voltage difference between the two systems that must be corrected by shedding load, adjusting generation or connecting reactive equipment before the tie is closed.

(c) Determine the best tie to be made among neighbors. Proceed to make the tie as recommended in the WECC Interconnection Disturbance Assessment and Restoration Guidelines in the OC Handbook.

2. Start-up power. Prior to restoring large customer loads, provide start-up power to generating stations and off-site power to nuclear stations where required. Adjacent entities shall establish mutual assistance arrangements for start-up power to expedite prompt restoration.

3. Synchronizing areas. As soon as voltage, frequency and phase angle permit, synchronize the islanded area with adjacent areas, using extreme caution to avoid unintentionally synchronizing large interconnected areas through relatively weak lines.

4. Restoring loads. Loads which have been shed during a disturbance shall only be restored when system conditions have recovered to the extent that those loads can be restored without adverse effect. If loads are reconnected by manual means or by supervisory control, they shall be restored only by direct action or order of the dispatcher, as generating capacity becomes available and transmission ties are reconnected. Loads shall not be manually restored until sufficient generating resources are available to return the ACE to zero within ten minutes. If automatic load restoration is used, it shall comply with the WECC Coordinated Off-Nominal Frequency Load Shedding and Restoration Plan and any other more stringent local program established in thorough coordination with neighboring systems and designed to avoid the possibility of recreating underfrequency, overloading ties, burdening neighboring systems, or delaying the restoration of ties. Relays installed to restore load automatically shall be set with varying and relatively long time delays, except in those cases where automatic load restoration is designed to protect against frequency overshoot.

E. Disturbance Reporting

Information and experience gained from studying disturbances which affect the operation of the interconnected power system are helpful in developing improved operating techniques.

1. Disturbance analysis. Entities and coordinated groups of entities within the WECC shall establish procedures and responsibility for collecting, analyzing and disseminating information and data concerning major disturbances. To facilitate post disturbance analyses, oscillographic and event recording equipment shall be installed at all key locations and synchronized to National Institute of Standards and Technology time.

2. Recommendations. Recommendations for eliminating or alleviating causes and effects of disturbances shall be made when appropriate.

F. Sabotage Reporting

Each operating entity or control area shall establish procedures for recognizing and reporting unusual occurrences suspected or determined to be acts of sabotage. These procedures shall cover recognizing acts of sabotage, disseminating information regarding such acts to the appropriate persons or entities within the area or within the interconnected power system, and notifying the appropriate local or regional law enforcement agencies.

Section 6 - Operations Planning

Each operating entity and coordinated group of operating entities is responsible for maintaining, and implementing as required, a set of current plans which are designed to evaluate options and set procedures for secure and reliable operation through a reasonable future time period. This section specifies requirements for operations planning to maintain the security and reliability of the interconnected power system.

A. Normal Operations

1. Operating studies. Studies conducted to obtain information which identifies operating limitations affecting transmission capability, generating capability, other equipment capability and power transfers between transmission providers or control areas shall be coordinated. To be considered acceptable, operating study results must be in compliance with the WECC Disturbance-Performance Table within the NERC/WECC Planning Standards.

2. Transfer limits under outage and abnormal system conditions. In addition to establishing total transfer capability limits under normal system conditions, transmission providers and control areas shall establish total transfer capability limits for facility outages and any other conditions such as unusual loads and resource patterns or power flows that affect the transfer capability limits.

3. Joint agreement on limits. All total transfer capability limits will be jointly agreed to by neighboring transmission providers or control areas.

B. Emergency Operations

1. Emergency plans. A set of plans shall be developed, maintained, and implemented as required by each operating entity or coordinated group of operating entities to cope with operating emergencies. These plans shall be coordinated with the Reliability Coordinators and other entities or coordinated groups of entities as appropriate. The plans shall be reviewed at least annually to ensure that they are up to date and a copy of the plans shall be provided to the Reliability Coordinators and shared with other entities as appropriate.

2. Loads requiring backup power. A reliable, adequate and automatic backup power supply shall be provided for the control center and other critical locations to ensure continuous operation of control equipment, communication channels, metering and recording equipment and other critical equipment during loss of normal power supply. Such backup power supply shall be adequate to carry equipment through a prolonged power interruption.

C. Automatic Load Shedding and System Sectionalizing

All control areas, coordinated groups of entities, and other entities serving load, shall jointly determine potential system separation points and resulting system islands and establish a program of automatic high-speed load shedding designed to arrest frequency decay. Such a program is essential in minimizing the risk of total system collapse in the event of separation, protecting generating equipment and transmission facilities against damage, providing for equitable load shedding among entities serving load and improving overall system reliability. Such islanding and load shedding

should be controlled so as to leave the islands in such condition as to permit rapid load restoration and reestablishment of interconnections.

1. WECC regional coordination. As new transmission facilities are constructed and study results and/or actual operating experience indicate differing islanding patterns, individual area load shedding programs shall be altered or integrated into other area programs to maintain an overall coordination of load shedding programs within the WECC.

A coordinated load shedding program shall be implemented to shed the necessary amount of load in each island area to arrest frequency decay, minimize loss of load and permit timely system restoration. Such island areas shall devise load shedding plans in accordance with the criteria outlined in the subsections that follow. As part of its participation in a coordinated load shedding program with neighboring entities, each entity serving load shall be equipped to automatically shed load at separate frequency levels over an appropriate frequency range. The load shedding shall be matched to the island area needs and coordinated within the island area.

2. Underfrequency relays. All automatic underfrequency load shedding comprising a coordinated load shedding program shall be accomplished by use of solid-state underfrequency relays. Electro-mechanical relays shall not be used as part of any coordinated load shedding program. In each island area, all relay settings shall be coordinated and based on the characteristics of that island area. It is essential that the underfrequency load shedding relay settings are coordinated with underfrequency protection of generating units and any other manual or automatic actions which can be expected to occur under conditions of frequency decline.

3. Technical studies. The coordinated automatic load shedding program shall be based on studies of system dynamic performance, under conditions which would cause the greatest potential imbalance between load and generation, and shall use the latest state-of-the-art computer analytical techniques. The studies shall be able to predict voltage and power transients at a widespread number of locations, as well as the rate of frequency decline, and shall reflect the operation of underfrequency sensing devices.

4. Load shedding steps. Automatic high-speed load shedding shall comply with the WECC Coordinated Off-Nominal Frequency Load Shedding and Restoration Plan so as to minimize the risk of further separation, loss of generation, excessive load shedding accompanied by excessive overfrequency conditions, and system shutdown.

5. Generators isolated to local load. Where practical, generators shall be isolated with local load to minimize loss of generation and enable timely system restoration in situations where the load shedding program has failed to arrest frequency decline.

6. Separation. The opening of intra-area and inter-area transmission interconnections by underfrequency relaying shall only be initiated after the coordinated load shedding program has failed to arrest frequency decline and intolerable system conditions exist.

7. Voltage reduction. If voltage reduction is utilized for manual load relief, such reduction shall not be made to the high voltage transmission system.

8. Protection from high frequency. In cases where area isolation with a large surplus of generation in relation to load requirements can be anticipated, automatic generator tripping or other remedial measures shall be used to prevent excessive high frequency and resultant uncontrolled generator tripping and/or equipment damage.

D. System Restoration

1. Restoration plan. Each transmission provider and control area shall have an up-to-date restoration plan and provide personnel training and telecommunication facilities needed to implement the restoration plan following a system emergency. Entities and coordinated groups of entities shall coordinate their restoration plans with other affected entities or coordinated groups of entities. All restoration plans shall be reviewed a minimum of every three years.

2. Synchronizing. To the extent possible, synchronizing locations shall be determined ahead of time and dispatchers shall be provided appropriate procedures for synchronizing. Such procedures should provide for alternative action to be taken if lack of information or loss of communication channels would affect resynchronization.

E. Control Center Backup

Each control area shall have a plan to provide continued operation in the event its control center becomes inoperable. For interconnected operations, the goal of this plan is to avoid placing a prolonged burden on neighboring control areas during a control center outage. Since most control centers differ in their internal functions and responsibilities, each control area should decide which specific functions, other than the basic functions shown below, will be necessary to continue their operations from an alternate location. These criteria do not obligate control areas to provide complete and redundant backup control facilities, but to provide essential backup capability. Each control area may, as an option, make appropriate arrangements with another control area to provide the minimum backup control functions in the event its primary control functions are interrupted. As part of its plan the control area is expected to comply with the following requirements (through automatic or manual means) as a minimum:

1. Notification. Provide prompt notification, which should include any necessary pertinent information, to other control areas in the event that primary control center functions are interrupted.

2. Proximity of Backup Control Center to primary Control Center. If the plan includes a backup control centers should be provided to prevent the outage of both facilities due to any credible threat including but not limited to the following:

1) Natural disasters, such as:

a. Earthquakes

b. Floods

c. Hurricanes

d. Tornadoes

2) Accidents, such as:

a. Fire

b. Internal environmental problems

c. Chemical spills

d. Plane crash

e. Explosion

f. Loss of communications, and

g. Catastrophic event

3. Communications. Maintain basic voice communication capabilities with other control areas.

4. Schedules. Maintain the status of all interarea schedules such that there is an hourly accounting of all schedules.

5. Critical interconnections. Know the status of and be able to control all critical interconnection facilities.

6. Tie line control. Provide basic tie line control capability to avoid burdening neighboring control areas with excessive inadvertent interchange.

7. Periodic tests. Conduct periodic tests of backup and control functions to ensure they are in working order.

8. Procedures and training. Provide adequate written procedures and training to ensure that operating personnel are able to implement all backup control functions when required.

Section 7 - Telecommunications

For a high degree of service reliability under normal and emergency operation, it is essential that all entities have adequate and reliable telecommunication facilities. A. Facilities

1. Between control centers. At least one main telecommunication channel with an alternate backup channel shall be provided between control centers of adjacent interconnected control areas, between control centers and key stations within a control area, and between other control areas as required.

2. Alternate facilities. Alternate facilities shall be provided to protect against interruption of essential telemetering, control and relaying telecommunications.

3. Standby power supply. Telecommunication facilities shall be provided with an automatic standby emergency power supply adequate to supply requirements for a prolonged interruption.

B. WECC Communication System

Control area control centers shall be connected to the WECC Communication System either directly or via pool communication facilities and the terminals shall be readily available to the dispatchers. Other transmission providers are encouraged to be connected to the WECC Communication System.

C. Loss of Telecommunications

Each control area shall have written operating instructions and procedures to enable continued operation of the system during loss of telecommunication facilities.

Section 8 -Operating Personnel and Training

To maintain a high degree of interconnected power system reliability, it is necessary that the interconnected power system be operated by qualified and knowledgeable personnel.

A. Responsibility and Authority

1. Written authority. Each system operator shall be delegated sufficient authority in writing to take any action necessary to ensure that the system or control area for which the operator is responsible is operated in a stable and reliable manner.

B. Requirements

1. Dispatchers/System Operators and plant operators. Dispatchers/System Operators and plant operators shall be qualified, trained and thoroughly indoctrinated in the principles and procedures of interconnected power system operation.

2. Other personnel. Other personnel involved in system operations, including, but not limited to, schedulers, contract writers, marketers, and energy accountants, shall be thoroughly familiar with the procedures and principles of interconnected power system operation which pertain to their job function.

C. Training

1. System Operator Training. WECC operating entities shall provide a coordinated training program fro system operators in compliance with NERC Policy 8.B.

2. Positions Requiring Trained System Operators. MORC 8.C applies to any position requiring a NERC Certified System Operator.

3. Continuing Education. Training shall be conducted regularly to keep all operating personnel involved in the operation of the interconnected power system abreast of changing conditions and equipment on their own system and on other interconnected systems and to ensure knowledge of and compliance with WECC criteria and procedures and NERC policies and standards.

3.1 Training Hours. Operating personnel shall receive at least 10 hours of NERC-approved continuing education training in every two calendar-year period, which shall be specific to WECC MORC, procedures, and guidelines. Individuals who have attained WECC System Operator certification and whose certificate is not more than one year old may receive the equivalent of 10 hours of credit for passing the WECC certification examination.

3.2 Required Training Hours. The training hours requirement in 3.1 above, must be met regardless of whether the system operator participates in the NERC continuing education program.

3.3 Training Programs. Training programs may include attendance at training sponsored by WECC, Operating Entities, or other vendors of training, including in-house developed training, provided such programs are NERC Continuing Education Program approved. Students and operating entities shall ensure course content is compatible with the 10-hour specific WECC requirements.

3.4 Training Documentation. Operating Entities shall maintain training documentation of operating personnel for at least three years, including but not limited to, the operator name, the number of NERC CE units earned, the date of the training, course title, and the NERC-approved course and/or provider ID number. All documentation shall be made available to WECC or a designated compliance monitoring review team upon request.

E. Information Sharing

1. Information requirements. Each operating entity's personnel shall respond to the information requirements of other operating entities, coordinated groups of operating entities, and the WECC Operations Committee.

June 19, 1970 Revised November 3, 1981 Revised August 11, 1987 Revised March 7, 1989 Revised August 8, 1989 Revised November 14, 1989 Revised March 13, 1990 Revised March 10, 1992 Revised November 5, 1992 Revised March 8, 1994 Revised December 2, 1994 Revised March 11, 1997 Revised July 29, 1997 Revised August 11, 1998 Revised March 8, 1999 Revised August 8, 2000 Revised December 7, 2000 Revised March 28, 2001 Revised April 18, 2002 Revised August 9, 2002 Revised April 23, 2004 Revised December 3, 2004 Revised April 6, 2005

WESTERN ELECTRICITY COORDINATING COUNCIL

DEFINITIONS PART IV

Western Electricity Coordinating Council

WESTERN ELECTRICITY COORDINATING COUNCIL

NERC/WECC PLANNING STANDARDS

AND

MINIMUM OPERATING RELIABILITY CRITERIA

D E F I N I T I O N S Revised August 9, 2002

WESTERN ELECTRICITY COORDINATING COUNCIL

NERC/WECC PLANNING STANDARDS AND

MINIMUM OPERATING RELIABILITY CRITERIA DEFINITIONS

Adequacy

The ability of a bulk electric system to supply the aggregate electrical demand and energy requirements of the customers at all times, taking into account scheduled and reasonably expected unscheduled outages of system components. Adjustment

Manual or automatic action following a disturbance. These actions are taken to prevent unacceptable system performance should a subsequent disturbance occur prior to system restoration. Angular Stability

Angular positions of rotors of synchronous machines relative to each other remain constant (synchronized) when no disturbance is present or become constant (synchronized) following a disturbance. If the interconnected transmission system changes too much or too suddenly, some synchronous machines may lose synchronism resulting in a condition of angular instability. Anti-Aliasing Filter

An analog filter installed at a metering point to remove aliasing errors from the data acquisition process. The filter is designed to remove the high frequency components of the signal over the AGC sample period. Area Control Error (ACE)

The instantaneous difference between actual and scheduled interchange, taking into account the effects of frequency bias (and time error or unilateral inadvertent interchange if automatic correction for either is part of the system’s AGC). Automatic Generation Control (AGC)

Equipment which automatically adjusts a control area’s generation from a central location to maintain its interchange schedule plus frequency bias.

Automatic Voltage Control Equipment Equipment which controls the output of reactive power resources based on local system voltage or loads. Black-Start Capability The ability of a generating unit or station to go from a shutdown condition to an operating condition and start delivering power without assistance from the power system. Blackout The disconnection of all electrical sources from all electrical loads in a specific geographical area. The cause of disconnection can be either a forced or a planned outage. Bulk Power Transformers Transformers which are connected in parallel with other elements of the bulk transmission network and therefore influence the loading and reliability of those other elements. A transformer which connects a radial load is not generally considered a bulk power transformer. Large generation step-up transformers are sometimes considered to be bulk power transformers. Cascading Cascading is the uncontrolled successive loss of system elements triggered by an incident at any location. Cascading results in widespread electric service interruption, which cannot be restrained from sequentially spreading beyond an area predetermined by appropriate studies. Contingency Single Contingency - The loss of a single system element under any operating condition or anticipated mode of operation. Most Severe Single Contingency - That single contingency which results in the most adverse system performance under any operating condition or anticipated mode of operation.

Multiple Contingency Outages - The loss of two or more system elements caused by unrelated events or by a single low probability event occurring within a time interval too short (less than ten minutes) to permit system adjustment in response to any of the losses. Control Area An area comprised of an electric system or systems, bounded by interconnection metering and telemetry, capable of controlling generation to maintain its interchange schedule with other control areas, and contributing to frequency regulation of the interconnection.

Controlled Action The switching of system elements as the planned response to system events or system conditions. For example, underfrequency and undervoltage load tripping are considered inherently controlled actions because the actions are the planned response to specific conditions on the system at the load locations. Out-of-step tripping of a line is considered an inherently controlled action because the action is the planned response to a specific condition on the line. Random line tripping caused by protective relay action in response to a non-fault condition such as a system swing is generally considered an uncontrolled action because this action is not the normal response intended for the protective relay. Controlled Islanding The controlled tripping of transmission system elements in response to system disturbance conditions to form electrically isolated islands which are relatively balanced in their composition of load and generation. This controlled action is taken to prevent cascading, minimize loss of load, and enable timely restoration. Credible That which merits consideration in operating and planning the interconnected bulk electric system to meet reliability criteria. Critical Generating Unit A unit that is required for the purpose of system restoration. Delayed Clearing

Delayed clearing occurs when the primary protection fails to clear the fault and backup relaying is required.

Disturbance

An unplanned event which produces an abnormal system condition such as high or low frequency, abnormal voltage, or oscillations in the system. Embedded System

The integrated electrical generation and transmission facilities owned or controlled by one organization that are integrated in their entirety within the facilities owned or controlled by another single system. Emergency Any abnormal system condition which requires immediate manual or automatic action to prevent loss of firm load, equipment damage, or tripping of system elements that could adversely affect the reliability of the electric system.

Emergency Limit The loading of a system element in amperes or MVA or the voltage level permitted by the owner of the element for a maximum duration of time such as thirty minutes or other similar short period. Entity A participant who is involved in the transmission, distribution, generation, scheduling, or marketing of electrical energy. Participants include, but are not limited to utilities, transmission providers, independent power producers, brokers, marketers, independent system operators, local distribution companies, and control area operators. Frequency Bias A value, usually given as MW/0.1 Hz, associated with a control area which relates the difference between scheduled and actual frequency to the amount of generation required to correct the difference. Governor Droop Governor droop is the decrease in frequency to which a governor responds by causing a generator to go from no load to full load. This definition of governor response is more precisely defined as “speed regulation” which is expressed as a percent of normal system frequency. For instance, if frequency decays from 60 to 57 hertz, a 5% change, a hydro generator at zero load with a governor set at a 5% droop would respond by going to full load. For smaller changes in frequency, changes in generator output are proportional. The more technically correct definition of governor droop is the change in frequency to which a governor responds by causing turbine gate position to move through its full range of travel, which is generally non-linear and a function of load. Inadvertent Interchange The difference between the control area’s net actual interchange and net scheduled interchange. Independent Power Producer A producer of electrical capacity and energy which owns the generation asset, but does not typically own any transmission or distribution assets. Also known as a Non-Utility Generator (NUG). Interconnected Power System A network of subsystems of generators, transmission lines, transformers, switching stations, and substations. Interruptible Imports, Exports and Loads Those imports, exports and loads which by contract can be interrupted at the discretion of the supplying system.

Island A portion of the interconnected system which has become isolated due to the tripping of transmission system elements. Load Responsibility A control area’s firm load demand plus those firm sales minus those firm purchases for which reserve capacity is provided by the supplier. Local Network A Local Network (LN) is a non-radial portion of a system and has been planned such that a disturbance may result in loss of all load and generation in the LN.

1. The LN is not a control area. 2. The loss of the LN should not cause a Reliability Criteria violation external to

the LN. Natural Frequency Response Characteristic Also called the “Natural Combined Characteristic” is the manner in which a system’s generation and load would respond to a change in system frequency in the absence of AGC. In practice, system regulation is achieved by the combined effects of generation governing and load governing. Planning Margin The transmission capability remaining in the system to accommodate unanticipated events. It can be embedded in conservative modeling and system representation assumptions (built-in margin), and can be explicitly established as well with operating limits and facility ratings. Some of the more important margins are related to current overloads, transient stability performance, oscillatory damping, post-transient voltage, and reactive support. If systems are modeled accurately, simulation results will provide an accurate relationship to the selected margin criteria. Simulations using built-in margins (conservative simplifications) produce an inaccurate sense of what the actual margins are. Radial System A radial system is connected to the interconnected transmission system by one transmission path to a single location. For the purpose of application of this Reliability Criteria,

1. A control area is not a radial system. 2. The loss of the radial system shall not cause a Reliability Criteria violation

external to the radial system. Reactive Reserves The capability of power system components to supply or absorb additional reactive power in response to system contingencies or other changes in system conditions. Reactive reserves may include additional reactive capability of generating units, and other synchronous machines, switchable shunt reactive devices, automatic fast acting

devices such as SVCs, and other power system components with reactive power capability. Regulating Margin The amount of spinning reserve required under non-emergency conditions by each control area to bring the area control error to zero at least once every ten minutes and to hold the average difference over each ten-minute period to less than that control area’s allowable limit for average deviation as defined by the NERC control performance criteria. Reliability The combination of Security and Adequacy, as defined in this section. Remedial Action Special preplanned corrective measures which are initiated following a disturbance to provide for acceptable system performance. Typical automatic remedial actions include generator tripping or equivalent reduction of energy input to the system, controlled tripping of interruptible load, DC line ramping, insertion of braking resistors, insertion of series capacitors and controlled opening of interconnections and/or other lines including system islanding. Typical manual remedial actions include manual tripping of load, tripping of generation, etc. Remedial Action Scheme

A protection system which automatically initiates one or more remedial actions. Also called Special Protection System. Reserve

Operating Reserve - That capability above firm system demand required to provide for regulation, load forecasting error, equipment forced and scheduled outages, and local area protection. It consists of spinning reserve and nonspinning reserve.

Spinning Reserve - Unloaded generation which is synchronized and ready to serve additional demand. It consists of Regulating Reserve and Contingency Reserve.

Regulating Reserve - An amount of spinning reserve responsive to Automatic Generation Control, which is sufficient to provide normal regulating margin.

Contingency Reserve - An additional amount of operating reserve sufficient to reduce Area Control Error to zero in ten minutes following loss of generating capacity, which would result from the most severe single contingency. At least 50% of this operating reserve shall be Spinning Reserve, which will automatically respond to frequency deviation.

Nonspinning Reserve - That operating reserve not connected to the system but capable of serving demand within ten minutes, or interruptible load that can be removed from the system within ten minutes.

Security

The ability of the bulk electric system to withstand sudden disturbances such as electric short circuits, unanticipated loss of system components or switching operations. Simultaneous Outage

Multiple outages are considered to be simultaneous if the outages subsequent to the first event occur before manual system adjustment can be made. For simulation purposes, it may be assumed that the outages occur at the same instant, or the outages may be staggered if the time sequence is known. System

The integrated electrical facilities, which may include generation, transmission and distribution facilities, that are controlled by one organization. System Adjusted System Adjusted means the completion of manual or automatic actions, acknowledging the outage condition, to improve system reliability and prepare for the next disturbance; i.e., change in generation schedules, tie line schedules, or voltage schedules. System Adjusted does not include automatic control action to maintain prefault conditions such as governor action, economic dispatch and tie line control, excitation system action, etc. Total Transfer Capability (TTC) The amount of electric power that can be transferred over the interconnected transmission network in a reliable manner while meeting all of a specific set of defined pre- and post-contingency system conditions. Uncontrolled The unanticipated switching of system elements at locations and in a sequence which have not been planned. Unscheduled Flow The difference between the scheduled and actual power flow, on a transmission path. Voltage Collapse

A power system at a given operating state and subject to a given disturbance undergoes voltage collapse if post-disturbance equilibrium voltages are below acceptable limits. Voltage collapse may be total (blackout) or partial and is associated with voltage instability and/or angular instability.

Voltage Instability A system state in which an increase in load, disturbance, or system change causes voltage to decay quickly or drift downward, and automatic and manual system controls are unable to halt the decay. Voltage decay may take anywhere from a few seconds to tens of minutes. Unabated voltage decay can result in angular instability or voltage collapse. Western Interconnection The interconnected electrical systems that encompass the region of the Western Electricity Coordinating Council of the North American Electric Reliability Council. The region extends from Canada to Mexico. It includes the provinces of Alberta and British Columbia, the northern portion of Baja California (Mexico), and all or portions of the 14 western states in between.

November 3, 1981 Revised August 11, 1987 Revised November 15, 1988 Revised March 9, 1993 Revised December 2, 1994 Revised March 11, 1997 Revised March 8, 1999 Revised April 18, 2002 Revised August 9, 2002

WESTERN ELECTRICITY COORDINATING COUNCIL

PROCESS FOR DEVELOPING AND APPROVING WECC STANDARDS PART V

Western Electricity Coordinating Council

WESTERN ELECTRICITY COORDINATING COUNCIL

PROCESS FOR DEVELOPING AND APPROVING WECC STANDARDS

Revised August 23, 2002

PROCESS FOR DEVELOPING AND APPROVINGWECC STANDARDS

Approved by WSCC Board of Trustees – August 24, 1999

Introduction

This is a previous Process of Western Systems Coordinating Council (WSCC) that hasbeen adopted for use by WECC pursuant to the WECC Bylaws, Section 2.4, Transition.

This document explains the process that WECC has established for announcing,developing, revising, and approving WECC Standards. WECC Standards include WECCOperating, Planning, and Market Interface Policies, Procedures, and Criteria, and theirassociated measurements for determining compliance. The process involves severalsteps:

� Public notification of intent to develop a new Standard, or revise an existingStandard.

� Subcommittee drafting stage.� Posting of draft for public comment.� Subcommittee review of all comments and public posting of decisions reached on

each comment.� WECC Market Interface Committee, Operating Committee, or Planning

Coordination Committee approval of proposed Standard.� Appeals Committee resolution of any “due process” or “technical” appeals.� WECC Board of Directors (Board) approval of proposed Standard.

The process for developing and approving WECC Standards is generally based on theStandard-making procedures used by the American National Standards Institute (ANSI),the Institute of Electrical and Electronics Engineers (IEEE), and the American Society ofMechanical Engineers (ASME):

1. Notification of pending Standard change before a wide audience of all “interestedand affected parties,”

2. Posting Standard change drafts for all parties to review,3. Provision for gathering and posting comments from all parties,4. Provision for an appeals process – both “due process” and “technical” appeals.

The issues of compliance and enforcement of the WECC Standards are currently beingaddressed and implemented through the WECC Reliability Management System (RMS).In cases requiring expediency, such as in the development of emergency operatingprocedures, the Market Interface Committee, Operating Committee, or PlanningCoordination Committee may approve a new or modified Standard. Any such Standardmust have an associated termination date and, even though already implemented, mustundergo the formal technical review and approval process. Should this Standard not be

formally approved through WECC’s Standards development and approval process it willcease to be in effect upon conclusion of the process.

Terms

Standards Committee. The Market Interface Committee (MIC), Operating Committee(OC) or Planning Coordination Committee (PCC)1. MIC, OC, and PCC will coordinatetheir responsibilities for those Standards that have a combination of market, operating,and planning implications.

Subgroup. A subcommittee, work group, or task force of the MIC, OC, PCC, or acombination of representatives from these committees; usually where WECC Standardsare drafted and posted for review2.

Due Process Appeals Committee. The committee that receives comments from thosewho believe that the “due process” procedure was not properly followed during thedevelopment of a Standard. The Due Process Appeals Committee consists of threeDirectors appointed by the Board Chair. The WECC Executive Director shall be the staffcoordinator for the Due Process Appeals Committee. Decisions of the AppealsCommittee will be based upon a majority vote.

Technical Appeals Committee. The committee that receives comments from those whobelieve that their “technical” comments were not properly addressed during thedevelopment of a Standard. The Technical Appeals Committee consists of the vice chairsof the Market Interface Committee, Operating Committee, Planning CoordinationCommittee, and a Director appointed by the Board Chair. The WECC Executive Directorshall be the staff coordinator for the Technical Appeals Committee. The TechnicalAppeals Committee will make assignments as necessary to existing WECC technicalwork groups and task forces, form new technical groups if necessary, and utilize othertechnical resources as required to address technical appeals. Decisions of the TechnicalAppeals Committee will be based upon a majority vote.

Steps

Step 1 – Request To Revise or Develop a Standard

Requests to revise or develop a Standard are submitted to the Board of Directors (Board),or to the Standards Committee (WECC MIC, OC, or PCC). Requests submitted to theBoard will be assigned to MIC, PCC, or OC, as appropriate, on a case by case basis.Requests submitted to MIC, PCC, or OC directly will be evaluated by these respectivecommittees to determine which committee should address the requests. In some

1 Membership in WECC’s Market Interface Committee, Planning Coordination Committee,

and Operating Committee is in accordance with WECC’s Bylaws.2 Formation of Subgroups is in accordance with the Market Interface Committee’s, Planning

Coordination Committee’s, and Operating Committee’s Organizational Guidelines.

instances a joint involvement will be needed to address requests that are applicable toplanning, operating, and market issues. Changes to the WECC Standards may be offeredby any individual or organization with a legitimate interest in electric system reliability,such as:

� Transmission owners� Generation owners� Independent System Operators (ISOs)� Transmission dependent utilities� Independent power producers� Power marketers� Customers, either retail or wholesale for resale� State agencies concerned with electric system reliability� WECC subgroups� Electric industry organizations

A request to revise or develop a Standard must include an explanation of the need for anew or revised Standard and be accompanied by a preliminary technical assessmentperformed by, or prepared under the direction of, the entity(ies) supporting the request.

Step 2 – Assignment to Subgroup

The Board or Standards Committee then assigns the request to whichever Subgroup(s) isresponsible for those issues. If a proposed new Standard or revision to an existingStandard has implications for any combination of planning, operations, or market issues,the Subgroup will include a composite of individuals having the appropriate planning,operations, and market expertise. Notification of such assignments will be posted on theWECC web site and sent to all parties that subscribe to the WECC Standards e-mail list.Interested parties may express their interest in participating in the deliberations of theSubgroup. The Subgroup membership will be administered in accordance with theWECC Bylaws.

Step 3 – Subgroup Begins Drafting Phase and Announces on WECC Web Site

The Subgroup will begin working on the new or revised request no later than at its nextscheduled or special meeting. A minimum of 30 days notice will be provided prior to allSubgroup meetings in which new or revised Standards will be developed. Notification ofsuch meetings will be posted on the WECC web site and sent to all parties that subscribeto the WECC Standards e-mail list. These meetings will be open to stakeholders having alegitimate interest in electric system reliability. The Subgroup Chair will allow someopportunity for outside comment and participation as the discussion progresses.However, the Subgroup Chair will not allow the discussion to interfere with productivediscussions by the Subgroup members.

The Subgroup will review the preliminary technical assessment provided by the requesterand may perform or request additional technical studies if considered necessary. The

Subgroup will complete an impact assessment report as part of its evaluation to assess thepotential effects of the requested Standards change. The Subgroup may request from theBoard or Standards Committee additional time to study the proposed new or revisedStandard if the Subgroup believes it necessary to fully assess the proposed change. If theSubgroup determines that a new Standard or change in an existing Standard is needed, itannounces the pending change, provides a summary of the changes it expects to draft, andprovides an explanation as to why the new Standard or change in an existing Standard isneeded. The announcement and the impact assessment report will be posted on theWECC web site and sent to all parties that subscribe to the WECC Standards e-mail list.If the Subgroup determines that a new or revised Standard is not needed, it prepares andposts the response to the party that submitted the proposal with a copy to the MIC, PCC,OC, or Board, as appropriate.

Step 4 – Draft Standard Posted for Comment

The Subgroup will post its first draft of the new or revised Standard on the WECC website and provide 60 days for comments. The draft must include specific measurements fordetermining compliance and the estimated costs of compliance. Comments on the draftwill be solicited from the WECC members and all individuals who subscribe to theWECC Standards e-mail list. Members of electric industry organizations may respondthrough their organizations, or directly, or both. All comments should be suppliedelectronically. WECC will then post all comments it receives on the WECC web site.

Step 5 – Subgroup Deliberates on Comments

Based on the comments it receives, plus its own review, the Subgroup will revise thedraft Standard as needed. It will document its disposition on all comments received, andpost its decisions on the WECC web site along with its second draft for either furtherindustry review or Standards Committee vote. If the Subgroup believes the technicalcomments are significant, it will repeat Steps 3 and 4, before sending a revised draft tothe Standards Committee. Steps 3 and 4 will be repeated as many times as considerednecessary by the subgroup to ensure an adequate review from a “technical” perspective.The number of days for comment on each new draft of a proposed new or revisedStandard will be 60 days, similar to the review period on the initial draft of the Standard.Parties who have their technical comments on a proposed Standard rejected by aSubgroup may write to the Standards Committee for further consideration of theircomments.

A majority vote of the Subgroup is required to approve submitting the recommendedStandard to the Standards Committee for a vote. The vote may be by mail, conferencecall and/or e-mail ballot.

Step 6 – Subgroup Submits Draft for Standards Committee Vote

The Subgroup’s final draft Standard is posted on the WECC web site and sent to theStandards Committee for a vote. The posting will include all comments that were not

incorporated into the draft Standard and the date of the expected Standards Committee’svote. The posting will also be sent to the Standards e-mail list with attachments.Proposed Standards will be posted no less than 303 days prior to the Standards Committeevote.

Standards may be voted on in their entirety or by individual provisions. The Subgroupwill determine how each Standard will be addressed for vote. The Subgroup will alsorecommend the subdivisions to be addressed and voted on as individual provisions. Tobe considered by the Standards Committee, any “no” votes, by Subgroup members, on aproposed Standard should be accompanied by a text explaining the “no” vote and ifpossible specific language that would make the Standard acceptable.

Step 7 – Standards Committee Votes on Recommendation to Board

The Standards Committee will vote on the draft Standard no later than at its nextscheduled or special meeting. A minimum of 304 days notice will be provided prior to allStandards Committee meetings in which new or revised Standards will be considered forapproval. Notification of such meetings will be posted on the WECC web site and sent toall parties that subscribe to the WECC Standards e-mail list. Whenever it determines thata matter requires an urgent decision, the Board may shorten the time period set forth inthis section, provided that: 1) notice and opportunity for comment on recommendationswill be reasonable under the circ*mstances; and 2) notices to Members will alwayscontain clear notification of the procedures and deadlines for comment. If the StandardsCommittee approves the Standard, it sends its recommendation, the draft Standard, andany comments on which the Standards Committee did not agree, plus StandardsCommittee minority opinions, to the Board for final approval. To be considered by theBoard, any “no” votes, by members of the Standards Committee, on a proposed Standardshould be accompanied by a text explaining the “no” vote and if possible specificlanguage that would make the Standard acceptable. Proposed Standards will be posted noless than 305 days prior to the Board vote. The date of the expected Board vote shall alsobe posted. The Standards Committee may amend or modify a proposed Standard. Thereasons for the modification(s) shall be documented, posted, and provided to the Board.If the Standards Committee’s recommendation changes significantly as a result ofcomments received, the committee will post the revised recommendation on the WECCweb site, provide e-mail notification to Members, and provide no less than ten (10) daysfor additional comment before reaching its final recommendation. Any parties that objectto the modifications may appeal to the appropriate Appeals Committee. These items shallall be posted on the WECC web site for general review. If the Standards Committee does 3 WECC Bylaws, Section 8.6 – require “not less than ten (10) days notice of all standing committeemeetings…”4 WECC Bylaws, Section 8.6 – require “not less than ten (10) days notice of all standing committeemeetings…” Section 8.7 – “All committee meetings of the WECC will be open to any WECC Member andfor observation by any member of the public.”5 WECC Bylaws, Section 7.5.1 – “Except as set forth in Section 7.5.2 regarding urgent business, all regularbusiness of the Board will occur at the Board meetings, at least twenty-one (21) days’ advance notice ofwhich has been provided…”

not approve the Standard, it may return the draft to the Subgroup for further work or itmay terminate the Standard development activity with the posting of an appropriatenotice to the Standards originator, the Subgroup, and the Board (if appropriate).

A majority vote of the Standards Committee, as specified in Section 8.5.4 of the WECCBylaws, is required to approve submitting the recommended Standard to the Board for avote. The vote may be by mail, and/or e-mail ballot.

Step 8 – Appeals Process

After approval and posting by the Standards Committee, any due process or technicalappeals are due, in writing, to the respective Due Process Appeals Committee orTechnical Appeals Committee within 15 days. If an Appeals Committee accepts theappellant’s complaint, it rejects the draft Standard and refers the complaint to theStandards Committee or Board for further consideration. If an Appeals Committee deniesthe complaint, it approves the Standard for referral to the Board. Deliberations of theAppeals Committees shall not exceed 15 days.

Step 9 – Board Approval

The Board will vote on the proposed Standard no later than at its next scheduled orspecial meeting. It will consider the Standards Committee’s recommendations andminority opinions, all comments that were not incorporated into the draft Standard, andinputs from the Due Process and Technical Appeals Committees. To preserve theintegrity of the due process Standards development procedure, the Board may not amendor modify a proposed Standard. If approved, the Standard is posted on the WECC website and all parties notified. If the Standard is not approved, the Board may return theStandard to the Standards Committee for further work or it may terminate the Standardactivity with an appropriate notice to the Standard originator and Standards Committee.These Board actions will also be posted.

A majority vote of the Directors present at a Board meeting, as specified in Section 7.2 ofthe WECC Bylaws, is required to approve the recommended Standard.

Step 10 – Standard Implementation or Further Appeals

Once the Board approves a new or modified Standard, all industry participants areexpected to implement and abide by the Standard in accordance with accepted WECCcompliance procedures. Should a party continue to object to the new or modifiedStandard, that party may through a WECC member have access to WECC’s alternativedispute resolution procedure to address its objections or seek other remedies asappropriate. Any and all parties to this Process retain the right of appeal to otherauthorities as the law allows.

Revised for Consistency with WECC Bylaws: June 21, 2002

Process for Developing and Approving WECC Standards

Request to BOD orStandards Committee (MIC, PCC,

or OC)

BOD or Standards CommitteeAssigns to Subgroup

SubgroupDrafts

Standard

Rejection and WhyStandard 1st Draft

(No) (Yes)

PostPost

SubgroupReviews

Comments

(60 Days)

Standard 2nd Draft Post

SubgroupReviews

Comments

Standard3rd or Final Draft

(Technical Comments)

(No TechnicalComments)

Post

StandardsCommittee

Votes

(30 Days)

Rejectionand Why Post

Send to BODfor Vote

To Subgroup forFurther Work

(Yes)

(Return)

PostPostAppeals on

Due Process15 Days

Appeals onTechnicalContent15 Days

Due ProcessAppeals Comm.

15 Days

TechnicalAppeals Comm.

15 Days

(Complaint Accepted)

(Yes) (Yes)

BOD Votes

(No)

(No) (No)(Complaint Denied)

PostPost

Post

Rejection and WhyTo Standards Committeefor Further Work

(Return) (No)

FINAL New orModified Standard

(Approve)

Post Commentsand Responses

(60 Days)

3 and

(30 Days)

IndustryImplements

WECCADR Process10

Post WithChanges

(10 Days)

(Or)

Any and all parties tothis Process retain theright of appeal to otherauthorities as the lawallows.

Created by:LSAG LSUPDT: 10/18/2006 Page 1

Meeting Summary - LCR Study Advisory Group (LSAG) September 28, 2006, ISO Offices in Folsom

Introductions On September 28, 2006 the inaugural meeting of the LSAG was held. Those in attendance are listed in Attachment 1. A package of reference material was available for the group. This material is also included in Attachment 1. The meeting was opened with introductions. It was noted that two additional representatives from the generator community would be added to the group. The names of these individuals were unknown at the time of the meeting. The agenda was reviewed and no changes were made. The purpose, representation, expectations, and objectives of the group were discussed. The CAISO explained that the group was intended to provide a representative cross-section of stakeholders that were technically qualified to assess the CAISO’s LCR study assumptions, criteria, and methodology in preparation for the 2008 LCR study. The CPUC schedule for 2008 LCR results will require the CAISO to initiate the 2008 analysis in January 2008. The LSAG is to review and evaluate the technical components of the LCR study and recommend changes, where needed, that could be implemented into the 2008 study. Members requested assurance that the focus would remain technical and that the LSAG recommendations would not circumvent all stakeholders having the opportunity to review the LSAG recommendations. The CAISO stated that the group’s only focus is technical issues and that follow-up stakeholder review of the LSAG’s findings and/or recommendations is the forum for determining the final LCR study assumptions, criteria and methodology. The CAISO stated that the LSAG’s first task is to provide a technical review of how the CAISO performed the 2007 LCR study. Specifically, the LSAG is being asked to consider whether or not the results the CAISO documented in its 2007 LCR study report reflect the study assumptions (load, generation dispatch, transmission configuration) the CAISO used;

• given the results of the power flow analysis (flows, currents, voltages, etc.) are directly related to the study assumptions and;

• given how the CAISO applied the NERC/WECC planning standards to the results. The CAISO did not ask the LSAG to agree or disagree with the LCR recommendations provided to the CPUC; rather, CAISO asked, “Given how the CAISO performed the study, were the CAISO answers reflective of the technical data and calculations used?” The CAISO stated that work on the 2008 LCR study could not move forward until the LSAG had reached a consensus that the CAISO’s 2007 study results are “technically” factual. Some felt that the focus of the LSAG should be looking to the future for the 2008 LCR studies, however others agreed that going over the study steps and assumptions used in 2007 was needed to move on to discussion of methodology for the 2008 LCR Study. Establishing these “technical” facts will focus and facilitate discussion on technical issues for the 2008 analysis. General Comments from the LSAG • Clarity about the LSAG objectives and the steps that will be taken after the LSAG group completes its

work is needed; • It is important to have the right proportion of people in the group to represent the broader stakeholder

population;

Created by:LSAG LSUPDT: 10/18/2006 Page 2

• Cannot get too caught up in whether people in the group agree or disagree; the larger stakeholder community should decide. It was reiterated that the LSAG is a technical group not a “stakeholder” process;

• Main issues that should be addressed first are (1) Deliverability issues (2) Clarify how consistency between the CEC load forecast and the load level used in these studies was achieved; (3) Transparency of operation procedures needed;

• There is a need to technically validate the 2007 study. A more elaborate and detailed explanation of the 2007 study assumptions, methodology, and criteria would help LSAG members better understand and assess how the CAISO came up with the results;

• Reflected in the CAISO LCR methodology used included protection for all deliverable units (In the 2007 LCR Study the CAISO used the same levels of generation from the units that were determined to be deliverable in the deliverability study which used Category B and C5 contingencies to determine generation deliverability) because the flow pattern can change, depending on contractual arrangements both within and outside of California;

• Concerned that the imports have been set only at the allocated OTC and not full path ratings. Also concerned about retiring any units without the express consent of the facility owner;

• Who will be doing the Stakeholder process, ISO or CPUC?;(Comment: the CAISO will conduct the effort to engage the larger stakeholder community. The CAISO is not aware of how the CPUC will proceed)

• Please clarify what the next steps will be; (Comment: the CAISO will work with the LSAG to better clarify the next steps from today through 2009);

• Manuals (tables, data) must be completed when the studies are done so that Stakeholders will have ample opportunity to review materials;

• Some members did not want to go through the 2007 details; believed that with CPUC adoption, the issue was moot; wanted to concentrate on 2008, without going through the 2007 studies;

• Some explanation on the security constrained least cost optimum power flow solution (SCOPF) that the CAISO will be using during MRTU and proposed that we use the same or very similar in our studies to determine the minimum LCR need in a certain local area. This software will automatically dispatch the system such that the next set of about 150 to 200 N-1 contingencies will be mitigated if they were to happen in the future. LSAG would discuss this methodology approach later.

2007 LCR Study Review • CAISO described FERC’s LGIP process, which determines resource deliverability and the CPUC’s RA

requirements, which set forth the system RA requirements of 115% to 117% of peak load and the local RA requirements (within the system RA requirements), as well as FERC indication that CAISO must meet all it’s needs with only units under RA contract, since in a not too distant future, those will be the only units obligated to respond to CAISO calls under Must-Offer. CAISO’s practices related to local area maintenance and continued by describing the input assumptions into the base cases and how they were achieved were also described;

• Explained how local area pockets have been defined and why; • Explained the methodology used to arrive at the criteria category B and C contingencies; • Explained how the CAISO addresses “real-time” contingencies and that the CAISO must plan and

operate the system in accordance with the NERC/WECC Planning Standards. The CAISO must to be able to support all category B and C5 contingencies 100% of the time (meaning that after these first set of Category B and common mode N-2 contingencies all elements have to be within their respective

Created by:LSAG LSUPDT: 10/18/2006 Page 3

applicable ratings. In all NERC C Category contingencies, load shedding is an option as long as it is done in a planned and controlled manner).

• Further explained that the category C3 requirements or N-1-1 have to be protected immediately after the first B contingency in order to make sure the system can support the second contingency and be within applicable ratings. In all NERC C Category contingencies including C3, load shedding is an option only after the second N-1 has occurred as long as it is done in a planned and controlled manner. Therefore the category C requirements (to protect against the next N-1) that the CAISO established in the 2007 studies actually need to be met before the second contingency happened in order to assure that all facilities are within their Applicable Ratings after the second contingency. CAISO noted that its 2007 LCR Study did not ask for any additional requirements that need to be maintained after the second of N-1-1 contingency have happened (when load drop is allowed). It was pointed out that the N-1-1 is no different from N-2 if there is no time available for a “manual” system adjustment between the first event and when the second event actually occurs. However, if there is “time” between the first and second contingencies, which is more common than not in operations, this time can be used to adjust the system between outages. As such, an N-1-1 (over-lapping outages) is not the same as an N-2 (simultaneous outage). N-1-1 is codified in Category C.3 in Table 1 of the NERC/WECC Planning Standards. After the first N-1, loading on all facilities must be within their emergency ratings, among other performance requirements, and load shedding is not allowed. The facility loadings can stay above the normal ratings, but below emergency ratings up to the time duration the emergency ratings are applicable. Where applicable, after a readjustment time period, system operators must decrease all loadings to levels where the system returns to a safe operating zone in preparation for the next worst N-1, which can be any facility in the system. After the next (second) N-1, load shedding is allowed to bring the loadings to within the facilities emergency ratings as long as it is done in a planned and controlled manner. N-2 is simultaneous common-mode outages. After the N-2 common mode contingency, load shedding is allowed to bring the loadings to within the facilities emergency ratings as long as it is done in a planned and controlled manner. There will not be the extra requirement to adjust the system in preparation of the next worst N-1. The above description also applies to other performance requirements in addition to facility loadings;

• Of key concern among the group is that any operational practices used in the LCR studies should be transparent and they should be included in the base case. In addition, all base cases should be made available to all with a WECC membership. Others should sign a confidentiality agreement to get these cases.

Issues Raised • Many group members were interested in the CAISO’s approach on protection of full deliverability for

units that have been already deemed deliverable through other proceedings (and studies) before single and category C5 contingencies. It was also noted that generation levels for individual generators within the generation pockets identified in the deliverability studies were set higher than historical values. In an area that has both a generation pocket and a load pocket, setting high levels of generation in the generation pocket could cause the LCR to increase in the load pocket in order to mitigate a potential congestion (deliverability) problem, which could have been avoided had the generation been set at historical (lower) levels. Consideration of impact on real time operations is necessary if historical patterns changes due to new market or contract situations. This issue was identified for more discussion by LSAG.;

• Interested in investigating seasonal studies in order to reduce LCR requirements in other then the summer season.; This is also one of CPUC’s objectives;

Created by:LSAG LSUPDT: 10/18/2006 Page 4

• Imports and how they are accounted for in the study; • Using low probability events (NERC/WECC Category C) is considered to stringent to establish LCR

requirements; • Description of the CEC load forecast for the entire state (CPUC and Non-CPUC jurisdictional entities)

was provided. More discussion was suggested at the next meeting; • Adding new transmission infrastructure should not increase load pocket areas. This issue was

identified for more discussion by LSAG. Parked Items (text as written on the flip chart) • Protection of deliverability of units outside the bubble and how to dispatch generation outside the

bubble to get inside the bubble (“for category B and C5 contingencies” - clarification text provided through LSAG comment);

• Load migration issue – annual showing – leaves capacity “stranded”; • Expanding load pockets due to additional transmission; • Determine how CEC develops load forecast; • Transparency of Operations Procedures needed. Overall Conclusions Reached • The CAISO explained the methodology of the 2007 LCR study. The Group indicated that there was a

better understanding of how CAISO derived the results of the study, however, not everyone was willing to agree that CAISO’s 2007 LCR results were “technically” consistent with how the CAISO performed the study. This will be discussed further at the next meeting.

• There was an extended discussion on the N-1-1 disturbance and that there is unanimous agreement that no load tripping is allowed after the first Category B event. This is clearly covered in the NERC Category B performance allowance. There was also unanimous agreement that load shedding is allowed after the second N-1 and that when the operators adjust the system to return to within a safe operating zone in preparation for the next worst N-1, no load shedding is allowed before the second N-1;

• Two key technical issues were identified for resolution: protection of deliverability of generation located outside a load pocket (this is a methodology issue) and expanding load pockets (this is a study assumption issue)

Other Items To Be Discussed In Future Meetings • Discussion of alternative “methodologies” for determining LCR. Alternatives can be discussed across a

longer term time period. • Requested discussion of criteria used for SCE’s LA Basin load pocket N-1, followed by N-2 on South of

Lugo – Believed to be well beyond NERC requirements vs. N-1 system readjustment and stay within an approved path rating – well within the CAISO/WECC/NERC standards.

Next Meeting October 20, 2006 at the CAISO

(PDF) DeShazo, Gary · Gary DeShazo - CAISO (LSAG Chair) To All: On behalf of the California ISO, I am pleased to welcome you as a member of the 2008 LCR Study Advisory Group ("LSAG") - DOKUMEN.TIPS (2024)

References