portland general electric companyâ€™s near term local transmission

PortlandGeneralElectricCompany’s

NearTermLocalTransmissionPlan

Forthe2012-2013PlanningCycle

Final Posted: December 21, 2012

Contents 1. Introduction .............................................................................................................................................. 3

1.1. Local Planning .................................................................................................................................... 3

1.2. Sub-Regional and Regional Coordination .......................................................................................... 3

2. Planning Process and Timeline ................................................................................................................. 3

Figure 1: PGE OATT Attachment K Eight Quarter Planning Cycle ......................................................... 4

Figure 2: Quarterly Customer Meetings ............................................................................................... 4

3. Transmission System Plan Inputs and Components ................................................................................. 5

3.1. PGE’s Transmission System ................................................................................................................ 5

Figure 3: Map of PGE’s Service Territory .............................................................................................. 5

Figure 4: PGE-Owned Transmission System Circuits ............................................................................ 6

Figure 5: PGE Circuit Miles Owned (By Voltage Level) .......................................................................... 6

3.2. Load Forecast ..................................................................................................................................... 6

Figure 6: Summer/Winter Loading Conditions and Corresponding Daily-Averaged Temperatures .... 7

Figure 7: Portland General Electric’s Historic & Projected Seasonal Peak Load ................................... 7

3.3. Forecasted Resources ........................................................................................................................ 7

3.4. Economic Studies ............................................................................................................................... 8

4. Methodology ............................................................................................................................................. 8

Figure 8: Powerflow Base Cases Used in 2012 Assessment ................................................................. 8

4.1. Steady State Studies........................................................................................................................... 9

4.2. Transient Stability Studies .................................................................................................................. 9

Figure 9: WECC Disturbance-Performance Table of Allowable Effects on Other Systems ................. 10

5. Results ..................................................................................................................................................... 10

5.1. Steady State Results – Near Term Evaluation .................................................................................. 10

5.2. Near Term Transient Stability .......................................................................................................... 11

5.3. Projects Currently Included in the Long Term Plan ......................................................................... 11

Appendix A: 5 Year Project List ................................................................................................................... 12

Carver-McLoughlin Phase 2 Project ........................................................................................................ 13

Carver-McLoughlin Phase 2 Project Map ............................................................................................ 14

Harrison-Marquam 115kV Project .......................................................................................................... 15

Harrison-Marquam 115kV Project Map .............................................................................................. 16

Cascade Crossing 500kV Project ............................................................................................................. 17

Cascade Crossing Project Map ............................................................................................................ 18

PGE Near Term Local Transmission Plan 2012 3

1. Introduction This 2012 Near Term Local Transmission Plan reflects Quarters 1 through 4 of the local transmission

planning process as described in PGE’s Open Access Transmission Tariff (OATT) Attachment K. The plan

includes all transmission system facility improvements identified through this planning process. A power

flow reliability assessment of the plan was performed which demonstrated that the planned facility

additions will meet NERC and WECC reliability standards.

PGE’s OATT is located on its Open Access Same-time Information System (OASIS) at

http://www.oatioasis.com/pge. Additional information regarding Transmission Planning is located in the

Transmission Planning folder on PGE’s OASIS. Unless otherwise specified, capitalized terms used herein

are defined in PGE’s OATT. This Near Term Plan constitutes PGE’s complete “expansion plan of the

Transmission Provider” as described in Section 12.2.3 of Attachment O to our OATT.

1.1. Local Planning

This Local Transmission Plan (LTP) has been prepared within the two-year process as defined in PGE’s

OATT Attachment K. The Near Term LTP identifies the Transmission System facility additions required to

reliably interconnect forecasted generation resources and serve the forecasted Network Customers’

load, Native Load Customers’ load, and Point-to-Point Transmission Customers’ requirements, including

both grandfathered, non-OATT agreements and rollover rights, over a five (5) year planning horizon.

Additionally, the LTP typically incorporates the results of any stakeholder-requested economic

congestion studies results that were performed. However, none were requested or incorporated during

this particular cycle.

1.2. Sub-Regional and Regional Coordination

PGE coordinates its planning processes with other transmission providers through membership in the

Northern Tier Transmission Group (NTTG) and the Western Electric Coordinating Council (WECC). PGE

uses the NTTG process for regional planning, coordination with adjacent regional groups and other

planning entities, and development of proposals to WECC for interconnection-wide planning. Additional

information is located in PGE’s OATT Attachment K, in our Transmission Planning Business Practice on

OASIS, and on the NTTG’s website at www.nttg.biz.

2. Planning Process and Timeline This plan is for the 2012-2013 planning cycle. PGE’s OATT Attachment K describes an eight (8) quarter

study and planning cycle. The planning cycle schedule is shown below in Figure 1.


Figure 1: PGE OATT Attachment K Eight Quarter Planning Cycle

Quarter Tasks

Ne

ar

Te

rm

E

ve

n Y

ea

rs

1 Select Near Term base cases and gather load data

2 Post Near Term methodology on OASIS, select one Economic Study for

evaluation

3 Select Longer Term base cases, post draft Near Term Plan on OASIS, hold

public meeting to solicit stakeholder comment

4 Incorporate stakeholder comments and post final Near Term plan on OASIS

Lon

ge

r T

erm

O

dd

Ye

ars

5 Gather load data and accept Economic Study requests

6 Select one Economic Study for evaluation

7 Post draft Longer Term plan on OASIS, hold public meeting to solicit

stakeholder comment

8 Post final Longer Term plan on OASIS, submit final Longer Term Plan to

stakeholders and owners of neighboring systems

PGE updates its Transmission Customers about activities and/or progress made under the Attachment K

planning process, during regularly scheduled customer meetings. Meeting announcements, agendas,

and notes are posted in the Customer Meetings folder on PGE’s OASIS. Figure 2 shows the meetings

held in 2012 and the meetings scheduled for 2013.

Figure 2: Quarterly Customer Meetings

Planning Cycle Quarter Meeting Date

1 February 22, 2012

2 May 17, 2012

3 September 8, 2012

4 December 5, 2012

5 March 5, 2013

6 June 4, 2013

7 September 10, 2013

8 December 3, 2013

*Meeting dates in italics are upcoming and subject to change.


3. Transmission System Plan Inputs and Components

3.1. PGE’s Transmission System

Portland General Electric’s (PGE) service territory covers more than 4,000 square miles and provides

service to over 850,000 customers. PGE’s service territory is confined within Multnomah, Washington,

Clackamas, Yamhill, Marion, and Polk counties in northwest Oregon, as shown in Figure 3.

Figure 3: Map of PGE’s Service Territory

PGE’s Transmission System is designed to reliably distribute power throughout the Portland & Salem

regions for the purpose of serving native load. In addition to the load-service transmission facilities, PGE

also maintains ownership of networked Transmission System circuits (See Figure 4) used to integrate

transmission and generation resources on the Bulk Electric System.


Figure 4: PGE-Owned Transmission System Circuits

Transmission Circuit Circuit Miles Transmission Path

Grizzly-Malin 500kV 178.5 miles COI1

Grizzly-Round Butte 500kV 15.6 miles

Boardman-Slatt 500kV 17.8 miles

Colstrip-Townsend #1 500kV 37.0 miles (15% ownership)

Colstrip-Townsend #2 500kV 36.9 miles (15% ownership)

Bethel-Round Butte 230kV 100.0 miles WOCS2

St Marys-Trojan 230kV 41.3 miles SOA3

Rivergate-Trojan 230kV 35.1 miles SOA

In total, PGE owns 1,666 circuit miles of sub-transmission/transmission at voltages ranging from 57kV to

500kV. (See Figure 5)

Figure 5: PGE Circuit Miles Owned (By Voltage Level)

Voltage Level Pole Miles Circuit Miles

500 kV 286 286

230 kV 325 383

115 kV 492 547

57 kV 431 451

3.2. Load Forecast

For load forecasting purposes, PGE’s transmission system is evaluated for a 1-in-3 peak load condition

during the summer and winter seasons for Near Term (years 1 through 5) and Longer Term (years 6

through 10) studies.

The 1-in-3 peak system load is calculated based on weather conditions that PGE can anticipate

experiencing once every three years. The summer (June 15th

through September 15th

) and winter

(November 15th

through February 15th

) loading seasons are considered the most critical study seasons

due to heavier peak loads.

1 California-Oregon Intertie

2 West of Cascades South

3 South of Allston


Figure 6: Summer/Winter Loading Conditions and Corresponding Daily-Averaged

Temperatures

Winter

1-in-2 28ºF

1-in-3 24ºF

1-in-5 21ºF

1-in-10 18ºF

1-in-20 15ºF

Figure 7: Portland General Electric’s Historic & Projected Seasonal Peak Load

(Projection is for a 1-in-3 Loading Condition)

As depicted in Figure 7, PGE’s all-time peak load occurred on December 21, 1998, with the Net System

Load4 reaching 4073 MW. Recent trends have shown that summer peak load in the Portland Metro area

is growing at a faster rate than winter peak load. PGE’s all time summer peak occurred on July 29, 2009

with the Net System Load reaching 3949 MW.

3.3. Forecasted Resources

The forecasted resources are comprised of generators, identified by network customers as designated

network resources, that are integrated into the wider regional forecasts of expected resources

committed to meet seasonal peak loads.

4 The Net System Load is the total load served by PGEM, including losses. This includes PGE load in all control areas, plus ESS

load, minus net borderlines.

Summer

1-in-2 79ºF

1-in-3 81ºF

1-in-5 83ºF

1-in-10 85ºF

1-in-20 87ºF


3.4. Economic Studies

Eligible customers or stakeholders may submit economic congestion study requests during either

Quarter 1 or Quarter 5 of the planning cycle. However, PGE has not yet received any study requests

during the 2012-2013 planning cycle.

4. Methodology PGE’s transmission system is designed to reliably supply projected customer demands and projected

Firm Transmission Services over the range of forecasted system demands. Studies are performed

annually to evaluate where transmission upgrades may be needed to meet performance requirements.

Powerflow Base Cases used in the assessment are derived from the Base Cases posted on the WECC

Bulletin Board.

PGE 1-in-3 load forecast is used to update the loads modeled in the WECC Base Cases.

Electrical facilities modeled in the cases have established normal and emergency ratings, as defined in

PGE’s Facility Rating Methodology document. A facility rating is determined based on the most limiting

component in a given transmission path.

Reactive power resources are modeled as made available in the WECC base cases. For PGE, reactive

power resources include shunt capacitor banks available on the 115kV transmission system (auto mode

- time-clock) and on the 57kV transmission system (auto mode - voltage control).

Known outages of generation or transmission facilities with durations of at least six months are

appropriately represented in the system models. When PGE’s spare equipment strategy could result in

the unavailability of major transmission equipment, the affected equipment is assumed out-of-service in

the Base Case system models.

Figure 8: Powerflow Base Cases Used in 2012 Assessment

The Bulk Electric System is evaluated for steady state and transient stability performance for planning

events described in Table 1 of the NERC Transmission Planning (“TPL”) standards. When system

Study Year WECC Base Case PGE Case NamePGE System

Load (MW)

Operating Case 2012 12hs4ap.sav 12HS_OPERATING 3435

Near Term Case 2016 16hs2a1p.sav 16HS_PLANNING 3633

Near Term (Sensitivity Study) 2016 16hs2a1p.sav 16HS_PLAN_SOA 3949

Longer Term Case 2019 19hs1a1p.sav 19HS_LONGER 3852

Operating Case 2012 12hw2ap.sav 12HW_OPERATING 3884

Near Term Case 2016 16hw2ap.sav 16HW_PLANNING 4033

Near Term (Sensitivity Study) 2016 16hw2ap.sav 16HW_PLAN_WOCS

Longer Term Case 2019 19hw1a1p.sav 19HW_LONGER 4229

FALL Near Term Off Peak 2016 16la1sap.sav 16LA_PLANNING

S

U

M

M

E

R

4301

2436

W

I

N

T


simulations indicate an inability of the systems to respond as prescribed in the NERC TPL standards, PGE

identifies projects and/or plans which are needed to achieve the required system performance

throughout the planning horizon.

4.1. Steady State Studies

The steady-state studies consider all contingency scenarios identified for Category B and Category C in

Table 1 of the NERC TPL standards. Category D contingencies are evaluated to document the potential

risks and consequence of such events.

For Category A (all elements in-service), PGE evaluates the system to ensure that the “normal”

equipment ratings are not exceeded during peak load conditions. The criteria for determining “normal”

equipment ratings are described in PGE’s Facility Rating Methodology document.

Capacity addition projects are developed when simulations indicate the system’s inability to meet the

steady-state performance requirements for Category B contingencies under 1-in-3 peak load conditions.

Under contingency scenarios, PGE evaluates the system to ensure that the “emergency” equipment

ratings (as defined in PGE’s Facility Rating Methodology document) are not exceeded during peak load

conditions.

For Category C events, PGE identifies distribution substations where manual “load-shedding” may be

required to ensure that the Transmission System remains within PGE’s defined operating limits.

Historical assessments show that cascading does not occur for any PGE Category B or Category C

contingency. Contingencies selected for Category D are studied and documented in terms of potential

risks and consequences of such events.

A written summary and schedule for implementation is available for any projects required to address

elements which load beyond 100% of their respective ratings in the Near Term and/or Longer Term

studies.

4.2. Transient Stability Studies

To comply with the NERC TPL standards, PGE evaluates the transient-stability performance of the Bulk

Electric System for contingencies to PGE equipment at 500kV and 230kV. The study evaluates 3Φ faults

to PGE facilities including: generators, bus sections, breaker failure, and loss of a double circuit

transmission line.

For all 500kV and 230kV breaker positions, PGE implements high-speed protection through two

independent relay systems utilizing separate current transformers for each set of relays to ensure

adequate protection. For a fault directly affecting these facilities, normal clearing is achieved when the

protection system operates as designed and faults are cleared within four to six cycles.

PGE implements breaker-failure protection schemes for its 500kV and 230kV facilities. Delayed clearing

occurs when a breaker fails to operate and the breaker-failure scheme clears the fault.


The transient stability study results are evaluated against the performance requirements outlined in the

NERC TPL Standards and against the WECC Disturbance-Performance Table of Allowable Effects on

Other Systems. The simulations durations are run to 10 seconds.

Figure 9: WECC Disturbance-Performance Table of Allowable Effects on Other Systems

NERC and

WECC Categories

Outage Frequency Associated

with the Performance Category (outage/year)

Transient

Voltage Dip

Standard

Minimum

Transient Frequency

Standard

Post

Transient Voltage

Deviation

Standard (See Note 2)

A Not Applicable Nothing in addition to NERC

B ≥ 0.33 Not to exceed

25% at load buses

or 30% at non-load buses.

Not to exceed

20% for more

than 20 cycles at

load buses.

Not below 59.6

Hz for 6 cycles or

more at a load bus.

Not to exceed 5% at any bus.

C 0.033 - 0.33

Not to exceed

30% at any bus.

Not to exceed

20% for more

than 40 cycles at load buses.

Not below 59.0

Hz for 6 cycles or

more at a load bus.

Not to exceed 10% at any bus.

D < 0.033 Nothing in addition to NERC

5. Results

5.1. Steady State Results – Near Term Evaluation

With all elements in-service, PGE does not have any regional transmission facilities that will exceed their

respective normal rating (NERC Category A) for 1-in-3 peak summer or peak winter loading conditions in

the Near Term assessment. PGE has identified transmission facilities that can approach their respective

emergency ratings during peak summer or winter conditions for the NERC Category B, C, and D

contingencies. All of the NERC Category B outages which result in overloads to PGE facilities are

addressed with the implementation of the identified transmission projects. The NERC Category C and D

outages which result in overloads to PGE facilities are addressed with load shedding, as permitted, on

PGE’s local distribution system. None of the contingencies evaluated will result in cascading from PGE’s

Control Area to another Control Area.


5.2. Near Term Transient Stability

The Near Term transient stability studies indicate that PGE’s Transmission System exhibits adequate

transient stability throughout the 500kV and 230kV transmission systems. The minimum transient

frequency response recorded did not dip below 59.6 Hz for any of the contingency events studied on

PGE’s Transmission System. Underfrequency Load Shedding (“UFLS”) relays are not affected because the

set point for UFLS relays is 59.3 Hz. The transient voltage dip did not exceed 25% at any load bus or 30%

at any non-load bus for any of the contingency events studied on PGE’s Transmission System.

5.3. Projects Currently Included in the Long Term Plan

There are three projects planned for implementation in the Near Term planning horizon, located in

three of PGE’s six regions. All of the transmission projects proposed are preliminary and are intended to

address steady-state thermal overload concerns on equipment during peak summer and/or peak winter

load.

The three planned projects are described in detail in Appendix A.


Appendix A: 5 Year Project List

Projects currently included in the Near Term Plan are:

• Carver-McLoughlin Phase 2 Project

• Harrison-Marquam 115kV Project

• Cascade Crossing 500kV Transmission Project (CCTP)

These projects are described in more detail on the following pages.


Carver-McLoughlin Phase 2 Project

• Project Purpose

o Maintain compliance with NERC Reliability Standards in the Near Term Planning Horizon.

The Near Term studies indicate that outages to transmission equipment at Carver and/or

McLoughlin may cause heavy loading to the Canemah-Carver 115kV circuit, the Carver-

McLoughlin 115kV circuit, or the Carver VWR1 transformer during peak summer loading

conditions.

• Project Scope

o Install a new circuit on the vacant side of the existing Carver-McLoughlin #2 230kV circuit.

The transmission system will be reconfigured such that this circuit will become the

Canemah-Carver 115kV circuit.

o The existing 115kV circuit which currently routes through Clackamas Substation will become

a Carver-McLoughlin 115kV circuit.

• Project Status

o In development. This project has an expected construction time of one year.

• Project Requirement Date

o This project is currently scheduled for implementation in 2016, and will be re-evaluated

annually in PGE’s Near Term assessments.


Carver-McLoughlin Phase 2 Project Map


Harrison-Marquam 115kV Project

• Project Purpose

o Maintain compliance with NERC Reliability Standards in the Near Term Planning Horizon.

PGE plans to energize Marquam substation in downtown Portland to provide distribution

service to the core area network. As a high reliability substation, Marquam will require

three transmission sources at 115kV. Two transmission sources will be provided by looping

in the existing Canyon-Urban 115kV line; however, a third transmission source will need to

be constructed from PGE’s Harrison substation.

• Project Scope

o Build out a 115kV ring bus at the PGE Harrison substation and disconnect transmission

facilities from the PACW Harrison substation. PGE Harrison substation will be sourced by

the Gresham-Harrison 115kV and Alder-Harrison 115kV lines.

o A third transmission circuit will be constructed from Harrison to Marquam, integrated in a

new Tri-Met Bridge crossing the Willamette River.

• Project Status

o In development. The transmission ductbank associated with the Tri-Met Bridge crossing is

currently under construction.


o The complete project is currently scheduled for energization in 2016.


Harrison-Marquam 115kV Project Map


Cascade Crossing 500kV Project

• Project Purpose

o Provide transmission capacity needed to serve growing energy needs in the Willamette

Valley using both traditional existing generation as well as renewable energy resources

located east of the Cascades.

• Project Scope

o Approximately 215 miles of 500 kV transmission running from the vicinity of Boardman,

Oregon to the vicinity of Salem, Oregon.

o Construction of new substations and supporting upgrades to existing substations.

o Additional system improvements in the Willamette Valley as may be required by the final

design.

• Project Status

o General Facilities Study issued on August 31, 2012. Individual interconnection and

transmission service request studies on hold under terms of May 18, 2012 FERC order

granting a one year waiver.

o Working on engineering studies of various design alternatives, including a double-circuit

option.

o Conducting the required permitting and routing studies in preparation for securing

necessary permits, easements, and rights of way.


o Tentatively set for 2016 or 2017.


Cascade Crossing Project Map

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