UE 335 - Portland General Electric · UE 335 – General Rate Case – Direct Testimony. I....

UE 335 / PGE / 1200 Macfarlane – Goodspeed

BEFORE THE PUBLIC UTILITY COMMISSION

OF THE STATE OF OREGON

UE 335

Marginal Cost of Service

PORTLAND GENERAL ELECTRIC COMPANY

Direct Testimony and Exhibits of

Robert Macfarlane Jacob Goodspeed

February 15, 2018

UE 335 / PGE / 1200 Macfarlane – Goodspeed / i

UE 335 - General Rate Case – Direct Testimony

Table of Contents

I. Introduction and Summary ......................................................................................... 1

II. Generation Marginal Cost Study ................................................................................ 2

III. Transmission Marginal Cost Study ........................................................................... 5

IV. Distribution Marginal Cost Study ............................................................................. 7

V. Customer Service Marginal Cost Study ................................................................... 13

VI. Area and Streetlights .................................................................................................. 16

VII. Qualifications .............................................................................................................. 17

List of Exhibits ..................................................................................................................... 18

UE 335 / PGE / 1200 Macfarlane – Goodspeed / 1

UE 335 – General Rate Case – Direct Testimony

I. Introduction and Summary

Q. Please state your names and positions. 1

A. My name is Robert Macfarlane. I am Interim Manager, Pricing and Tariffs for Portland 2

General Electric Company (PGE). I am responsible, along with Mr. Goodspeed, for the 3

development of the marginal cost studies. 4

My name is Jacob Goodspeed. I am a Senior Regulatory Analyst in Pricing and 5

Tariffs for PGE. I am also responsible for the development of the marginal cost studies. 6

Our qualifications are included at the end of this testimony. 7

Q. What is the purpose of your testimony? 8

A. Our testimony describes the methodologies and results of PGE’s generation, 9

transmission, distribution, customer service, and street lighting marginal cost of service 10

studies. PGE Exhibit 1201 provides a summary of these marginal costs by component. 11

The summary lists costs by PGE rate schedule for generation capacity and energy, 12

transmission, subtransmission, substation, feeder backbone and tapline, transformers, 13

service laterals, meters, and customer service costs. Rate schedule changes are 14

discussed in PGE Exhibit 1301. 15

Q. What is the purpose of the distribution and customer marginal cost studies? 16

A. The purpose is to calculate the incremental or marginal unit cost of service for various 17

categories (e.g., distribution substations, feeders, billing). These unit costs, expressed 18

as costs per customer, costs per kilowatt (kW) of demand, or costs per kilowatt hour 19

(kWh) are then used to allocate the functional revenue requirements as described in 20

PGE Exhibit 1300. 21



II. Generation Marginal Cost Study

Q. What methodology do you propose in this docket? 1

A. We propose a long-run generation methodology that explicitly takes into account the 2

cost of marginal generation capacity, long-run marginal energy costs, and renewable 3

energy requirements. 4

Q. Please describe the steps used to develop the long-run generation allocation 5

methodology. 6

A. The generation marginal cost analysis involves the following inputs and steps: 7

1. Determine both a long-run marginal energy cost and a long-run marginal 8

capacity cost by first defining the marginal long-run generation resource as a 9

combined cycle combustion turbine (CCCT) used to provide both energy and 10

capacity. 11

2. From this analysis, separately estimate the capacity and energy components 12

as follows: 13

a. Estimate the marginal cost of future capacity as the fixed cost of an “F-14

class” simple cycle combustion turbine (SCCT). 15

b. Use these SCCT fixed costs as the portion of the CCCT fixed cost that is 16

assigned to capacity with the remaining CCCT fixed costs assigned to 17

energy. 18

c. Add 17% reserve requirements to the SCCT capacity costs consistent 19

with PGE’s 2016 Integrated Resource Plan (IRP). 20

3. Finally, express the capacity and energy values in real levelized terms. 21



Q. Has the methodology used to develop the long-run generation allocation changed 1

since PGE’s 2018 General Rate Case filed as Docket No. UE 319? 2

A. No. 3

Q. What are the sources of the overnight capital costs for the resources used in the 4

model? 5

A. PGE’s 2016 IRP is the source of the overnight capital costs1 used in the analysis. 6

Q. Please describe how you determined the proportion of marginal energy costs 7

attributable to the CCCT and the generic wind farm. 8

A. We weighted the marginal energy cost by the Renewable Portfolio Standard (RPS) 9

target percentages for each year. For example, if the RPS target is 20% in a given year, 10

the weighting is 20% wind and 80% thermal. The weightings reflect the revised RPS 11

targets included in Senate Bill 1547.2 12

Q. What is the source of your long-term gas price forecast? 13

A. We used the Wood Mackenzie long-term gas price forecast dated November 2017 for 14

the Sumas and AECO hubs, blended with near-term forward curves. We equally 15

weighted the projected burner tip prices from these two hubs. 16

Q. Did you include the projected costs of carbon dioxide compliance in your analysis? 17

A. No. On both the national and state level, no carbon tax exists. Any potential future 18

carbon tax is uncertain. The exclusion of carbon tax from this analysis is consistent 19

with the treatment of carbon tax for purposes of PGE’s avoided cost calculations used 20

in Tariff Schedule 201. 21

1 Cost of the project as if no interest were included during its construction. 2 78th Oregon Legislative Assembly, 2016 Regular Session



Q. Did you include production tax credits in your analysis? 1

A. Yes. A production tax credit value of 60% was used, based on a resource that 2

commences construction in 2018. 3

Q. What is the fully allocated cost of the wind farm? 4

A. The cost of the generic wind plant exclusive of wheeling is estimated at $42.05 per 5

megawatt hour (MWh) in real levelized 2019 dollars. 6

Q. How did you estimate each rate schedule’s long-run marginal cost of energy? 7

A. We multiply each schedule’s monthly on-peak and off-peak load forecast by the 8

corresponding monthly on-peak and off-peak long-term energy value. 9

Q. How do you shape the annual long-run marginal cost of energy into monthly 10

on-peak and off-peak values? 11

A. We shape the annual long-run marginal energy cost into monthly on-peak and off-peak 12

values based on the monthly on-peak and off-peak Mid-Columbia forward prices used 13

in PGE’s net variable power cost model (i.e., the Multi-area Optimization Network 14

Energy Transaction model, also known as MONET3). 15

3 See PGE Exhibit 300 for a description of MONET.



III. Transmission Marginal Cost Study

Q. Have you performed a transmission unit marginal costs analysis for this docket? 1

A. Yes. The methodology is the same as that used in UE 319. Based on the transmission 2

project, contained in PGE Exhibit 1202, we calculate a unit marginal cost of 3

$11.98/kW.4 4

Q. Is PGE a transmission-dependent utility? 5

A. Yes. PGE is a transmission-dependent utility that purchases about 3,700 megawatts 6

(MW) of transmission from Bonneville Power Administration (BPA) to integrate its 7

generation and purchased power. PGE operates a limited transmission system 8

comprised of approximately 268 pole miles of 500 kilovolts (kV) lines and 270 pole 9

miles of 230 kV lines, some of which is functionalized to generation. At the 230 kV 10

level, the system ties into seven BPA bulk power substations around the Portland area. 11

PGE also has ties into three BPA bulk power substations in the Salem area. The 12

primary function of the 230 kV system that is functionalized to transmission is to 13

provide an interface to the main grid for load service. 14

Q. What drives additions to PGE’s existing transmission system? 15

A. PGE’s transmission planners evaluate whether additions to PGE’s existing transmission 16

system are needed to meet North American Electric Reliability Corporation (NERC) 17

and Western Electric Coordinating Council (WECC) reliability standards for serving 18

customers on the basis of 1-in-3 peak load conditions during the summer and winter 19

seasons for both the near term and the long-term.5 The winter period is defined as 20

4 The transmission marginal cost value is shown in the provided transmission marginal cost study. 5 Ibid, page 6.



November 1st through March 31st, and the summer is defined as June 1st through 1

October 31st, therefore ten months in all. Because the transmission planners use ten 2

months of peak loads when evaluating reliability, we extend the peak load criteria 3

slightly to twelve months when calculating unit marginal costs. A twelve month 4

criteria, or twelve coincident peak (12CP) is also consistent with how the Federal 5

Energy Regulatory Commission (FERC) determines PGE’s Open Access Transmission 6

Tariff prices. 7



IV. Distribution Marginal Cost Study

Q. Which marginal distribution costs do you calculate? 1

A. We calculate marginal distribution costs separately for subtransmission, substations, 2

distribution feeders (backbone facilities and local facilities), line transformers 3

(including services), and meters. 4

Q. How do you calculate the marginal unit costs of subtransmission and substations? 5

A. We calculate the subtransmission unit costs using the subtransmission marginal 6

investment cost from UE 319 escalated for inflation. We calculate substation marginal 7

costs using a recent engineering estimate of the cost to construct a substation. We then 8

divide the cost by the substation transformer capacity in kW, and annualize the cost per 9

kW. Customers served at subtransmission voltage are excluded from this calculation 10

because they supply their own substation. Columns (B) and (C) in PGE Exhibit 1201, 11

page 3, summarize subtransmission and substation costs. 12

Q. How do you calculate the marginal unit feeder costs? 13

A. We estimate distribution feeder unit costs in the following manner: 14

1. Perform an analysis that places customers by class on the distribution feeder 15

from which they are currently served. 16

2. Eliminate any distribution feeders from which we cannot obtain customer 17

information, and which do not conform to “typical” standards. Examples of 18

these “non-typical” feeders are feeders serving customers at 4 kV, and 19

feeders that serve downtown core areas. 20



3. Perform an inventory of the wire types and sizes for each feeder. Standardize 1

these wire types and sizes to current specifications and then calculate the cost 2

of rebuilding these feeders in today’s dollars. 3

4. Segregate the wire types and sizes into mainline feeders and taplines. 4

Mainline feeders are typically capable of carrying larger loads and are 5

generally closer to the substations from which they originate. Taplines are 6

typically capable of carrying smaller loads and can be remote from 7

substations. 8

5. For each feeder, allocate the mainline cost responsibility of each customer 9

class based on the customer class’s proportionate contribution to non-10

coincident peak (NCP). Calculate a unit cost per kW by totaling the feeder 11

cost responsibilities and dividing by the sum of each class’s NCP. 12

6. For each feeder, allocate the tapline cost responsibility of each customer class 13

based on its proportionate design demand (estimated peak at the line 14

transformer). Calculate a unit cost per kW for both poly- and single- phase 15

customers by totaling the feeder cost responsibilities and dividing by the sum 16

of each schedule’s design demand. 17

7. Annualize the mainline and tapline unit costs by applying an economic 18

carrying charge. 19

8. Separately estimate the unit costs of customers with peak loads greater than 4 20

MW who are typically on dedicated distribution feeders. Calculate these 21

marginal unit costs (per customer) as the average distance between the 22



substation and the customer-owned facilities. Finally, apply the annual 1

carrying charge to annualize the cost per customer. 2

9. Separately estimate the per-customer costs of customers served at 3

subtransmission voltage. This is done by first calculating the average 4

distance from the point at which subtransmission voltage customers connect 5

into the subtransmission system from their substation. Then we multiply this 6

average distance by the current cost per wire mile and annualize the costs. 7

Columns (D), (E), and (F) on page 3 of PGE Exhibit 1201 summarize feeder 8

mainline and tapline costs. 9

Q. Why do you propose to calculate the marginal costs of feeders on the basis of class 10

size rather than by rate schedule? 11

A. We propose this because past marginal feeder costs analyses have resulted in extremely 12

high unit marginal costs for the irrigation Schedules 47 and 49 due to their preponderant 13

location on remote feeders within PGE’s service territory. This cost result for the 14

irrigation schedules seems to be due to geographical distinction rather than due to 15

economies of scale. Because PGE does not price by geographical area, we propose the 16

class size distinction when calculating unit marginal feeder costs. For all other 17

marginal cost categories, we separately measure the unit marginal costs of the irrigation 18

schedules. 19

Q. Please describe any other considerations in calculating unit feeder costs. 20

A. Currently, many municipalities require undergrounding of taplines within subdivisions 21

and commercial areas. Therefore, we used the current cost of underground facilities 22

exclusively in our marginal feeder tapline cost calculations. 23



Q. How do you calculate marginal transformer and service costs? 1

A. We calculate each schedule’s marginal transformer and service costs by estimating the 2

cost of providing the average customer within specific load sizes with a service lateral 3

and a line transformer (secondary delivery voltage only). For smaller customers such as 4

those on Schedules 7 and 32, we estimate the average number of customers on a 5

transformer in order to appropriately calculate the per customer share of transformer 6

costs. Column (G) on page 3 of PGE Exhibit 1201 summarizes transformer and service 7

costs. 8

Because primary and subtransmission voltage customers supply their own 9

transformer and service laterals, the marginal cost for these customers is zero. 10

Q. Please describe how you calculate the marginal costs of meters. 11

A. We calculate marginal meter costs as the weighted installed cost of an Advanced 12

Metering Infrastructure (AMI) meter for each rate schedule or load size, and then apply 13

an annual carrying charge. Column (H) on page 3 of PGE Exhibit 1201 summarizes 14

meter costs. 15

Q. How do you allocate distribution operations and maintenance (O&M) to each 16

distribution category and ultimately to each rate schedule? 17

A. We allocate test-period distribution O&M by distribution category to the rate schedules 18

in proportion to each schedule’s respective usage and per unit marginal capital cost. All 19

of the distribution costs by functional category, on page 3 of PGE Exhibit 1201, are 20

inclusive of test-period distribution O&M. 21



Q. The UE 319 Partial Stipulation required PGE to evaluate the marginal capital 1

costs of primary and secondary Distribution Facilities and the maintenance costs 2

contained in FERC Account Nos. 583, 584, 593, and 594 and estimate the amounts 3

attributable to secondary voltage service conductors, secondary voltage 4

conductors, and primary voltage conductors. Has PGE met this requirement? 5

A. Yes. In consultation with Service and Design Project Managers, who in turn spoke with 6

field personnel, we estimated the percentage of time field personnel spend on 7

maintaining secondary service conductors. After estimating the approximate $6.1 8

million costs of maintaining secondary service conductors by the appropriate 9

Accounting Work Order (AWO), we deduct the estimated secondary service conductor 10

maintenance cost amounts from the total of the FERC maintenance amounts. Then, for 11

the appropriate cost categories, we allocate the amount of expense attributable to 12

primary voltage and secondary voltage conductors by the objective measure of relative 13

circuit wire miles. This decomposition of the FERC maintenance accounts is contained 14

in the feeder O&M work papers accompanying this filing. In addition to the allocation 15

of maintenance costs described above, we reassigned approximately $60,000 in 16

transformer costs from overhead and underground line maintenance to the transformer 17

maintenance account. 18

Column (F) on page 3 of PGE Exhibit 1201 summarizes secondary distribution 19

facilities costs. 20

Q. Please explain how this impacts the maintenance cost of secondary conductors. 21

A. PGE allocates its projected test period distribution feeder maintenance costs on the 22

basis of each schedule’s marginal costs; hence, attributing primary voltage and 23



secondary voltage conductor maintenance costs separately will result in changes in how 1

test period distribution feeder maintenance costs are allocated to the rate schedules. 2

Primary voltage conductor maintenance costs are allocated to mainline feeders and 3

local facilities. Secondary voltage conductor maintenance costs are allocated to local 4

facilities based on the estimated percentage of secondary voltage conductors serving 5

each rate schedule. This results in higher allocated test period maintenance costs to 6

customers using secondary facilities. 7



V. Customer Service Marginal Cost Study

Q. What is the purpose of the customer service marginal cost study? 1

A. The purpose is to calculate the incremental cost of customer service for each rate 2

schedule. PGE incurs costs in managing its relationship with customers, including 3

handling customer communications, measuring usage, maintaining records, and billing. 4

As such, customer service costs increase as the number of customers PGE serves 5

increases. Column (I) on page 3 of PGE Exhibit 1201 summarizes marginal customer 6

costs. 7

Q. Does PGE use the forecasted test year expenses in the customer marginal cost 8

study? 9

A. Yes. PGE uses forecasted costs for the 2018 test period and 2017 actual costs to 10

develop the 2019 test year Customer Service Marginal Cost Study. These costs are 11

found in FERC Account Nos. 902, 903, 905, 908, and 909. The 2019 forecasted costs 12

are also referred to as budget amounts in this testimony. 13

Q. Is the study’s methodology the same as in PGE’s last rate case – UE 319? 14

A. Yes, the methodology is the same. As in UE 319, the costs are allocated by PGE 15

accounts directly on the basis of cost causation. A few accounts are allocated based on 16

a sub-allocation of the other account costs. After the costs are spread across rate 17

schedules, the final result is marginal costs for each rate schedule by each of the three 18

functionalized categories: metering, billing, and other services. 19



Q. Please provide an example of how you calculate metering marginal costs. 1

A. The 2019 forecasted amount for FERC Account No. 902, Field Collection Department, 2

is allocated based on manual meter reads and a weighted percentage of customers (less 3

unmetered lighting and signals). 4

Q. Please provide examples of how you calculate billing marginal costs. 5

A. Examples include: 6

• The costs for Retail Receivables and Field Collections are allocated based on 7

percentage of adjusted write-offs by rate schedule. 8

• Customer Information System billing costs are allocated by the number of 9

customers, except streetlights and traffic signals. 10

• The costs for Printing and Automated Mail Services are allocated based on 11

the number of paper bills delivered. 12

• Network Data Operation costs are allocated based on the number of 13

customers with meters, which excludes unmetered lighting and traffic 14

signals. 15

Q. Please provide examples of how you calculate other customer service marginal 16

costs. 17

A. Examples include: 18

• The budget amount associated with the Customer Contact Operations is 19

allocated by the number of customers on rate schedules using up to 200 kW. 20

• The budget amount for the Direct Access Operations Department is allocated 21

by the number of customers participating in the direct access program. 22



• The budget amount for the Special Attention Operations Department is 1

allocated based on the number of residential customers. 2

• The Solar Payment Option and Net Metering Operations budget amounts are 3

allocated by the number of customers participating in the programs. 4



VI. Area and Streetlights

Q. Please describe how you price Area Lights and Streetlights. 1

A. We price the investment portion (i.e., poles and luminaires) of providing lighting 2

service using a real levelized annual revenue requirement. Lighting schedule prices 3

will be updated to reflect the Cost of Capital adopted by the Commission in this 4

proceeding. 5

Q. Please describe how you calculate the amount of outdoor lighting maintenance. 6

A. Similar to UE 319, we propose to base the test period lighting maintenance amount on 7

the incurred maintenance amounts during PGE’s most recent complete 5-year 8

relamping cycle (2005-2009), before conversion to Light-Emitting Diode (LED) area 9

and streetlights commenced. More specifically, we express the historical maintenance 10

amounts on a per-light basis, and then escalate this per-light maintenance figure for 11

inflation. A further reduction is made for LED street and area lights since (1) their 12

maintenance is significantly less than other lights, and (2) the years used in the most 13

recent 5-year re-lamping cycle do not include LEDs. Following this, we allocate 14

maintenance to each type of luminaire based on the marginal cost of maintenance study. 15

Q. Do you provide a summary exhibit of the proposed pole and luminaire prices? 16

A. Yes. This summary is provided in PGE Exhibit 1305. 17



VII. Qualifications

Q. Mr. Goodspeed, please state your educational background and qualifications. 1

A. I received a Bachelor of Arts degree in Public Policy from Washington State University 2

and a Master of Business Administration degree from the University of New Orleans. I 3

accepted my current role at PGE in 2016, and have previously worked in Senior Pricing 4

Analyst and Pricing Lead roles for Entergy Services, Inc., providing pricing and rate 5

design support to Entergy Louisiana LLC., Entergy Texas Inc., Entergy New Orleans 6

Inc., and Entergy Arkansas Inc. I have also served as a financial analyst in Entergy’s 7

nuclear organization. 8

Q. Mr. Macfarlane, please state your educational background and experience. 9

A. I received a Bachelor of Arts business degree from Portland State University with a 10

focus in Finance. I have been Interim Manager, Pricing and Tariffs since January of 11

2018. My prior title was Regulatory Consultant. Since joining PGE in 2008, I have 12

worked as an analyst in the Rates and Regulatory Affairs Department. My duties at 13

PGE have included pricing, revenue requirement, Public Utility Regulatory Policies Act 14

avoided costs, and regulatory issues. From 2004 to 2008, I was a consultant with Bates 15

Private Capital in Lake Oswego, OR, where I developed, prepared, and reviewed 16

financial analyses used in securities litigation. 17

Q. Does this conclude your testimony? 18

A. Yes. 19



VIII. List of Exhibits

PGE Exhibit Description

1201 Marginal Cost Study

1202 PGE’s Draft Near Term Local Transmission Plan

UE 335 / PGE / 1201Macfarlane – Goodspeed / Page 1

PORTLAND GENERAL ELECTRIC2019 MARGINAL ENERGY COSTS

MarginalBusbar Energy

Schedule Energy (MWh) CostSchedule 7 8,017,734 $303,025,693Schedule 15 16,701 $567,660Schedule 32 1,700,609 $63,345,918Schedule 38 32,692 $1,260,508Schedule 47 23,002 $874,342Schedule 49 69,419 $2,638,126Schedule 83 2,946,960 $110,562,096Schedule 85 2,944,147 $109,544,583Schedule 89 541,085 $19,873,332Schedule 90-P 1,850,474 $67,405,013Schedule 91/95 57,146 $1,942,392Schedule 92 2,667 $96,756

TOTALS 18,202,636 $681,136,419

UE 335 / PGE / 1201 Macfarlane – Goodspeed / Page 2

PORTLAND GENERAL ELECTRIC2019 MARGINAL ENERGY AND CAPACITY COSTS

Thermal Thermal Wind WeightedCapacity Marginal Marginal Capacity Marginal

SCCT Energy Energy Costs EnergyYear $/kW-year $/MWh $/MWh RPS $/kW-year $/MWh2019 106.42 34.08 42.05 15.00% 106.42 35.282020 108.54 34.76 42.89 20.00% 108.54 36.392021 110.71 35.46 43.75 20.00% 110.71 37.112022 112.92 36.16 44.62 20.00% 112.92 37.862023 115.18 36.89 45.51 20.00% 115.18 38.612024 117.48 37.62 46.42 20.00% 117.48 39.382025 119.83 38.38 47.35 27.00% 119.83 40.802026 122.23 39.14 48.30 27.00% 122.23 41.612027 124.67 39.93 49.26 27.00% 124.67 42.452028 127.16 40.72 50.25 27.00% 127.16 43.292029 129.70 41.54 51.25 27.00% 129.70 44.162030 132.29 42.37 52.28 35.00% 132.29 45.842031 134.94 43.21 53.32 35.00% 134.94 46.752032 137.63 44.08 54.39 35.00% 137.63 47.692033 140.38 44.96 55.47 35.00% 140.38 48.642034 143.19 45.86 56.58 35.00% 143.19 49.612035 146.05 46.77 57.71 45.00% 146.05 51.702036 148.97 47.71 58.87 45.00% 148.97 52.732037 151.95 48.66 60.04 45.00% 151.95 53.782038 154.98 49.63 61.24 45.00% 154.98 54.86

Real Levelized $106.42 $34.08 $42.05 $106.42 $36.31

NPV $1,360 $436 $538 $1,360 $464Nominal Levelized $124.05 $39.73 $49.02 $124.05 $42.33Real Levelized $106.42 $34.08 $42.05 $106.42 $36.31

Composite Income Tax Rate 27.15%Property Tax Rate 1.45%Inflation Rate 2.00%Capitalization: Preferred 0.00% 0.00% 0.00% Common 50.00% 9.50% 4.75% All Equity 50.00% 4.75% Debt 50.00% 4.97% 2.49%Cost of Capital 7.24%

After-Tax Nominal Cost of Capital 6.56%After-Tax Real Cost of Capital 4.47%

UE 335 / PGE / 1201 Macfarlane – Goodspeed / Page 3

PORTLAND GENERAL ELECTRICSUMMARY OF TRANSMISSION, DISTRIBUTION AND CUSTOMER MARGINAL COST STUDIES

FEEDER FEEDER SECONDARY TRANSFORMERTRANSMISSION SUBTRANSMISSION SUBSTATION MAINLINE TAPLINE TAPLINE & SERVICE METER CUSTOMER

COSTS COSTS COSTS COSTS COSTS COSTS COSTS COSTS COSTSSCHEDULE ($/kW) ($/kW) ($/kW) ($/kW) ($/kW) ($kW) ($/Customer) ($/Customer) ($/Customer)

(A) (B) (C) (D) (E) (F) (G) (H) (I)Schedule 7 Residential

Single-phase $11.98 $12.15 $12.24 $20.41 $15.71 $4.39 $83.97 $19.43 $63.37Three-phase $11.98 $12.15 $12.24 $20.41 $15.71 $4.39 $140.51 $58.07 $63.37

Schedule 15 Residential $11.98 $12.15 $12.24 $21.38 $18.06 $2.72 $2.89 N/A $11.23

Schedule 15 Commercial $11.98 $12.15 $12.24 $21.38 $18.06 $2.72 $2.89 N/A $13.01

Schedule 32 General ServiceSingle-phase $11.98 $12.15 $12.24 $24.70 $23.90 $3.34 $150.15 $17.23 $80.60Three-phase $11.98 $12.15 $12.24 $24.70 $11.35 $1.59 $236.86 $72.71 $80.60

Schedule 38 TOUSingle-phase $11.98 $12.15 $12.24 $24.54 $24.34 $2.04 $196.72 $58.07 $162.10Three-phase $11.98 $12.15 $12.24 $24.54 $12.08 $1.01 $581.00 $130.80 $162.10

Schedule 47 IrrigationSingle-phase $11.98 $12.15 $12.24 $24.70 $23.90 $10.77 $57.73 $79.11Three-phase $11.98 $12.15 $12.24 $24.70 $11.35 $21.43 $86.54 $79.11

Schedule 49 IrrigationSingle-phase $11.98 $12.15 $12.24 $24.54 $24.34 $144.93 $58.07 $147.14Three-phase $11.98 $12.15 $12.24 $24.54 $12.08 $144.93 $71.36 $147.14

Schedule 83 Secondary General ServiceSingle-phase $11.98 $12.15 $12.24 $24.54 $24.34 $2.04 $388.14 $57.73 $249.80Three-phase $11.98 $12.15 $12.24 $24.54 $12.08 $1.01 $1,050.66 $129.44 $249.80

Schedule 85 Secondary General Service $11.98 $12.15 $12.24 $19.54 $7.12 $2,419.89 $162.33 $1,315.52

Schedule 85 Primary General Service $11.98 $12.15 $12.24 $19.54 $7.12 $0.00 $1,805.54 $1,315.52

Schedule 89 Secondary $11.98 $12.15 $12.24 $76,614 N/A $14,124.26 $175.85 $9,594.75($/Customer)

Schedule 89 Primary $11.98 $12.15 $12.24 $76,614 N/A $0.00 $1,809.13 $9,594.75($/Customer)

Schedule 89 Subtransmission $11.98 $12.15 N/A $77,041 N/A N/A $19,774.56 $9,594.75($/Customer)

Schedule 90 Primary $11.98 $12.15 $12.24 $365,087 NA $0.00 $1,805.54 $33,539.76

Schedules 91 & 95 Streetlighting $11.98 $12.15 $12.24 $21.38 $18.06 $5.05 $2.89 N/A $989.77

Schedules 92 Traffic Signals $11.98 $12.15 $12.24 $21.38 $10.30 $0.14 $9.19 N/A $986.10

Portland General Electric Company’s Longer Term Local Transmission Plan For the 2016-2017 Planning Cycle December 28, 2017

UE 335 / PGE / 1202 Macfarlane - Goodspeed / Page 1

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

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

1.2. Regional and Interregional 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 ........................................................................................................................ 8

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

3.5 Stakeholder Submissions .................................................................................................................... 8

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

Figure 8: Powerflow Base Cases Used in 2017 Assessment ................................................................. 9

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

4.2. Transient Stability Studies ................................................................................................................ 10

Figure 9: WECC Disturbance-Performance Table of Allowable Effects on Other Systems ................. 11

5. Results ..................................................................................................................................................... 12

5.1. Steady State Results – Longer Term Evaluation .............................................................................. 12

5.2. Longer Term Transient Stability ....................................................................................................... 12

Appendix A: 10 Year Project List ................................................................................................................. 13

Lower Columbia Resiliency Project ......................................................................................................... 14

North Hillsboro Capacity Project ............................................................................................................ 15

Orenco-Sunset 115kV Reconductor Project ........................................................................................... 16

Northern Substation 115kV Conversion Project ..................................................................................... 17


PGE Longer Term Local Transmission Plan 2017 3

1. IntroductionThis 2017 Longer Term Local Transmission Plan reflects Quarters 5 through 8 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://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.

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 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 ten (10) 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.

Projects identified in the Longer Term Local Transmission Plan’s six (6) to ten (10) year planning horizon are not committed projects and are subject to modification and/or withdrawal. Projects described herein are not part of PGE’s Expansion Plan as described in Section 12.2.3 of Attachment O to PGE’s OATT.

1.2. Regional and Interregional 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 for interregional planning, and development of proposals to WECC. 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 TimelineThis plan is for the 2016-2017 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

Nea

r Ter

m

Ev

en Y

ears

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

Long

er T

erm

Odd

Yea

rs

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 2017 and the meetings scheduled for 2018.

Figure 2: Quarterly Customer Meetings

Planning Cycle Quarter Meeting Date 5 March 7, 2017 6 June 6, 2017 7 September 12, 2017 8 December 5, 2017 1 March 13, 2018 2 June 12, 2018 3 September 11, 2018 4 December 11, 2018

*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 825,000 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.


i" ' ..

-·· Coonties , .. , .. .-

Cdum .. ---- ~IHlh ---<--. ....

SOUTHERN

EASTERN

CENTRAL

EASTERN

SOUTHERN

- WESTERN


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

Colstrip-Townsend #1 500kV 37.3 miles (15% ownership)

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

Bethel-Round Butte 230kV 99.2 miles WOCS2

St Marys-Trojan 230kV 41.4 miles SOA3

Rivergate-Trojan 230kV 35.1 miles SOA

In total, PGE owns 1,590 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 268 268

230 kV 270 319

115 kV 496 551

57 kV 430 451

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 1st through October 31st) and winter (November 1st through March 31st) load seasons are considered the most critical study seasons due to heavier peak loads and high power transfers over PGE’s T&D System to its customers. PGE defines the seasons to align with the Peak Reliability Seasonal System Operating Limits Coordination Process, Appendix ‘V’.

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. PGE’s all time summer peak occurred on July 29, 2009 with the Net System Load reaching 3949 MW.

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


[ ,,

Portland General Electric Historic & Projected Seasonal Peak Load

(Projection is for a 1..jn-J Loading Condition)

4,200 ~---------------------------------------------

4,000 +----------1+------------------------------------l

~ 3,600 +----~ ---~ --~ --- - - ~ - ------1- - ---1-- -----------------------------;

...J ... cu .. ll.

3,200 +-----------------------------------------------;

--Summar - - Winter

3,000 +-----------------------------------------------< 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028

Year


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.

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 did not receive any study requests during the 2016-2017 planning cycle.

3.5 Stakeholder Submissions Any stakeholder may submit data to be evaluated as part of the preparation of the draft Longer Term Local Transmission Plan and/or the development of sensitivity analyses, including alternative solutions to the identified needs set out in prior Local Transmission Plans, Public Policy Considerations and Requirements, and transmission needs driven by Public Policy Considerations and Requirements. However, PGE did not receive any such data submissions during the 2016-2017 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.

PGE maintains system models within its planning area for performing the studies required to complete the System Assessment. These models use data that is provided in WECC Base Cases in accordance with the MOD-010-0 and MOD-012-0 reliability standards. Electrical facilities modeled in the cases have established normal and emergency ratings, as defined in PGE’s Facility Ratings Methodology document. A facility rating is determined based on the most limiting component in a given transmission path, in accordance with the FAC-008-3 reliability standard.

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

Studies are evaluated for the Near Term Planning Horizon (years 1 through 5) and the Longer Term Planning Horizon (years 6 through 10) to ensure adequate capacity is available on PGE’s transmission system. The load model used in the studies is obtained from PGE’s corporate forecast, reflecting a 1-in-3 demand level for peak summer and peak winter conditions. Known outages of generation or transmission facilities with durations of at least six months are appropriately represented in the system models. Transmission equipment is assumed to be out of service in the Base Case system models if there is no spare equipment or mitigation strategy for the loss of the equipment.

In the Near Term, studies are performed for the following:



• System Peak Load for either Year One or Year Two • System Peak Load for Year Five • System Off-Peak Load for one of the five years

Sensitivity studies are performed for each of these cases by varying the study parameters to stress the system within a range of credible conditions that demonstrate a measurable change in performance. PGE alters the real and reactive forecasted load and the transfers on the paths into the Portland area on all sensitivity studies. For peak system sensitivity cases, the 1-in-10 load forecast is used.

Studies are evaluated at peak summer and peak winter load conditions for one of the years in the Longer Term Planning Horizon.

Figure 8: Powerflow Base Cases Used in 2017 Assessment

The Bulk Electric System is evaluated for steady state and transient stability performance for planning events described in Table 1 of the NERC TPL-001-4 reliability standard. When system simulations indicate an inability of the systems to respond as prescribed in the NERC TPL-001-4 standard, PGE identifies projects and/or Corrective Action Plans which are needed to achieve the required system performance throughout the Planning Horizon.

4.1. Steady State Studies PGE performs steady-state studies for the Near-Term and Long-Term Transmission Planning Horizons. The studies consider all contingency scenarios identified in Table 1 of the NERC TPL-001-4 reliability standard to determine if the Transmission System meets performance requirements. These studies also assess the impact of Extreme Events on the system expected to produce severe system impacts.

The contingency analyses simulate the removal of all elements that the Protection System and other automatic controls are expected to disconnect for each contingency without Operator intervention. The analyses include the impact of the subsequent tripping of generators due to voltage limitations and tripping of transmission elements where relay loadability limits are exceeded. Automatic controls simulated include phase-shifting transformers, load tap changing transformers, and switched capacitors and reactors.

Study YearOrigin WECC

Base Case PGE Case NamePGE System Load (MW)

Year One/Two Case 2019 2021 HS2 19 HS PLANNING 3665Year Five Case 2022 2022 HS1 22 HS PLANNING 3762Year One/Two Sensitivity 2019 2021 HS2 19 HS SENSITIVITY 3789Year Five Sensitivity 2022 2022 HS1 22 HS SENSITIVITY 3889Long Term Case 2027 2027 HS1 27 HS PLANNING 3986

Year One/Two Case 2018-19 2020-21 HW1 18-19 HW PLANNING 3694Year Five Case 2022-23 2021-22 HW2 22-23 HW PLANNING 3792Year One/Two Sensitivity 2018-19 2020-21 HW1 18-19 HW SENSITIVITY 3879Year Five Sensitivity 2022-23 2021-22 HW2 22-23 HW SENSITIVITY 3981Long Term Case 2027-28 2026-27 HW1 27-28 HW PLANNING 3921

Near Term Off Peak Case 2019 2017 LSP2-S 19 LSP PLANNING 2427Near Term Off Peak Sensitivity 2019 2017 LSP2-S 19 LSP SENSITIVITY 2427

SPRING

SUMMER

WINTER


1•


Cascading is not allowed to occur for any contingency analysis. If the analysis of an Extreme Event concludes there is Cascading, an evaluation of possible actions designed to reduce the likelihood or mitigate the consequences and adverse impacts of the event(s) is completed.

Capacity addition projects are developed when simulations indicate the system’s inability to meet the steady-state performance requirements for P1 events. For P2-P7 events, PGE identifies distribution substations where manual post-contingency “load-shedding” may be required to ensure that the Transmission System remains within the defined operating limits.

4.2. Transient Stability Studies PGE evaluates the voltage and transient stability performance of the Transmission System for contingencies to PGE and adjacent utility equipment at 500kV and 230kV. The studies evaluate single line-to-ground and 3ϕ faults to these facilities, including generators, bus sections, breaker failure, and loss of a double-circuit transmission line. Extreme events are studied for 3ϕ faults with Delayed Fault Clearing.

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. 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; and the majority of 115kV facilities. Delayed clearing occurs when a breaker fails to operate and the breaker-failure scheme clears the fault. Facilities without delayed clearing are modeled as such in the contingency definition.

The transient stability results are evaluated against the performance requirements outlined in the NERC TPL-001-4 reliability standard and against the WECC Disturbance-Performance Table of Allowable Effects on Other Systems (Table I). The simulation durations are run to 20 seconds.



Figure 9: WECC Disturbance-Performance Table of Allowable Effects on Other Systems5

WECC and NERC Categories

Outage Frequency Associated with the

Performance Category Transient Voltage Dip

Standard Minimum Transient Frequency Standard

Post Transient Voltage Deviation Standard

A (P0) Not Applicable Nothing in addition to NERC

B (P1) ≥ 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 (P2-P7) 0.033-0.33


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.


D (Extreme) < 0.033 Nothing in addition to NERC

Contingency analyses simulate the removal of all elements that the Protection System and other automatic controls expected to disconnect for each contingency without Operator intervention. The analyses include the impact of the subsequent:

- Successful high speed (less than one second) reclosing and unsuccessful high speed reclosing into a Fault where high speed reclosing is utilized

- Tripping of generators due to voltage limitations - Tripping of Transmission lines and transformers where transient swings cause Protection System

operation based on generic or actual relay models - Automatic controls simulated include generator exciter control and power system stabilizers,

static var compensators, power flow controllers, and DC Transmission controllers.

Cascading is not allowed to occur for any contingency analysis. If the analysis of an Extreme Event concludes there is Cascading, an evaluation of possible actions designed to reduce the likelihood or mitigate the consequences and adverse impacts of the event(s) is completed.

5 The WECC TPL-001-WECC-CRT Regional Criterion is currently undergoing a revision to adapt the new categories (P0-P7) in the NERC TPL-001-4 reliability standard.



Corrective Action Plans are developed if the stability studies indicate that the system cannot meet the TPL-001-4 and WECC performance requirements.

- P1: No generating unit pulls out of synchronism - P2-P7: When a generator pulls out of synchronism, the resulting apparent impedance swings do

not result in the tripping of any Transmission system elements other than the generating unit and its directly connected facilities

- P1-P7: Power oscillations exhibit acceptable damping

5. Results

5.1. Steady State Results – Longer Term Evaluation There are no contingency loading or voltage concerns on PGE’s system in the Longer Term Planning Horizon for NERC TPL-001-4 Categories P1, P2, P3, P4, and P5. NERC TPL-001-4 Category P6 and P7 contingency overloads and voltage concerns 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. Longer Term Transient Stability The Longer 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 Longer Term Plan

There are 3 projects currently planned for implementation in the Longer Term Planning Horizon. Projects described in this Longer Term Plan are subject to modification and/or withdrawal. Potential projects are described in detail in Appendix A.



Appendix A: 10 Year Project List

Potential projects currently included in the Longer Term Plan are:

• Lower Columbia Resiliency Project

• North Hillsboro Capacity Project

• Orenco-Sunset 115kV Reconductor Project

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



Lower Columbia Resiliency Project

• Project Purpose

o Increase transfer capacity into the Portland area via the South of Allston transfer path

• Project Scope

o Construct a new 230kV transmission line from Trojan substation to Harborton Substation

• Project Status

o Preliminary planning

• Project Requirement Date

o No date established; TBD



North Hillsboro Capacity Project

• Project Purpose

o Increase capacity in the North Hillsboro area

• Project Scope

o Construct a new 230kV substation in the north Hillsboro area

o Loop the Harborton-Horizon 230kV line into the new substation

o Install a 230/115 kV bulk power transformer at the new substation

o Loop the Shute-West Union 115kV line into the new substation

o Reterminate the Shute substation end of the Shute-Sunset #1 115kV line at the new substation

• Project Status






Orenco-Sunset 115kV Reconductor Project

• Project Purpose

o Increase the capacity of the Orenco-Sunset 115kV line to eliminate thermal overload concerns

• Project Scope

o Reconductor the Orenco-Sunset 115kV circuit (approx. 3 miles) to 795 ACSS.

• Project Status






Northern Substation 115kV Conversion Project

• Project Purpose

o Upgrade the Northern substation and convert it to 115kV

• Project Scope

The Curtis-Rivergate #2 115kV circuit will be looped in to the new breaker station, creating a Curtis-Northern 115kV circuit and a Northern-Rivergate 115kV circuit.

• Project Status





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