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Transmission Formula Rate 2015 Annual Update

July 10, 2015

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Agenda

– Annual Update Overview– Overview of Projection and True-Up– Schedule 1– Additional Information– Handouts

Attachment H-1 Variance Analysis: PacifiCorp Formula Rate Model 2015 Projection compared to 2014 Projection

Attachment H-1 Variance Analysis: PacifiCorp Formula Rate Model 2014 True-Up compared to 2014 Projection

Transmission Plant Additions Detail (Enclosure 6) Energy Imbalance Market (EIM) cost information

(Enclosure 8)

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Protocols Definitions – “Protocols”

PacifiCorp’s formula transmission rates, including those in Schedules 1, 7 and 8 of the Tariff (but excluding rates or charges in any other Schedule of the Tariff), shall be implemented in accordance with the Formula Rate Implementation Protocols (Attachment H-2 of the Tariff).

– “Interested Party” A transmission customers of PacifiCorp, a state commission in a state where

PacifiCorp serves retail customers, any entity having standing in a FERC proceeding investigating the Formula Rate, and staff of FERC.

– “Formula” and “Formula Rate” The formula rate template (“Formula”) contained in Attachment H-1 which

includes Schedule 1 and the Protocols in Attachment H-2 (together comprise the “Formula Rate”).

– “Rate Year” The Formula Rate is applicable to service on and after June 1 of a given calendar

year through May 31 of the subsequent calendar year.– “Annual Transmission Revenue Requirement” or “ATRR”

PacifiCorp follows instructions in the Formula Rate to annually calculate (project and true-up where applicable) its ATRR.

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Protocols Definitions (cont’d)– “Annual Update”

The Projection and True-Up process is referred to as the Annual Update. By May 15 of the current year, calculate the projected ATRR, and transmission

rates for the next Rate Year (the “Projection” and herein, the “2015 Projection”) and Schedule 1 rate for the next Rate Year in accordance with the Formula Rate.

• Based on the most recent FERC Form No. 1 data, limited projections of current calendar year transmission plant and long-term firm loads in Attachment 9A to the Formula Rate will be adjusted.

By May 15, calculate the True-Up for the preceding calendar year in accordance with the Formula Rate (the “True-Up” and herein, the “2014 True-Up”).

• Shall include actual data for the prior calendar year compared to the data projected in the Annual Update for the same calendar year - a refund or surcharge shall be issued to customers including interest.

– “Publication Date” Informational filing with FERC by May 15 of the Annual Update and information

posted to OASIS showing the calculation of such Annual Update (the date of such posting is referred to herein as the "Publication Date");

Notification of refund or surcharge notices sent to customers. – “Information Request Period”

Up to 180 calendar days after the Publication Date, Interested Parties may submit requests for information supporting the Annual Update.

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OASIS Postings

PacifiCorp has posted the following materials to OASISwww.oasis.oati.com/ppw/[Documents > PacifiCorp OASIS Tariff/Company Information > OATT Pricing > 2015 Transmission Formula Annual Update]

– FERC informational filing– Formula Rate 2015 Projection and variance analysis– Formula Rate 2014 True-Up and variance analysis– Additional materials:

Transmission Plant Additions Detail Material Changes Summary EIM Cost Information 2015 Actuarial Study Reports (PBOP details)

– Information request process narrative (includes IntraLinks info)

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OASIS Postings: 2015 Annual Update

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OASIS Postings: Variance Analysis

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OASIS Postings: Currently Effective Rates

Rates were posted to OASIS May 15, 2015, effective June 1, 2015

2015 Projection: 28.51 $/kW-year

2014 True-Up: 25.52 $/kW-year

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2014 FERC Form No. 1

The 2014 FERC Form No. 1 may be found by clicking on “Regulatory Filings” under “Financial Information” at the following link on PacifiCorp’s website:

www.pacificorp.com/about/fi.html

The above navigation redirects to the Berkshire Hathaway Energy Company website accessible directly at:

www.berkshirehathawayenergyco.com/investors/regulatory-filings

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2014 True-Up Refund

– True-Up covers calendar year during which two projected rates were in effect

2014 Jan Feb March April May June July Aug Sept Oct Nov Dec

2013 Projection25,856 $/MW-yr (2,154.69 $/MW-month)(effective June 2013 through May 2014)

2014 Projection27,536 $/MW-year (2,294.64 $/MW-month)

(effective June 2014 through May 2015)

2014 True-Up 25,524 $/MW-year (2,127.01 $/MW-month)

(calculated for calendar year 2014)

Monthly Refund January through May 2014

2,154.69 – 2,127.01 = 27.68 $/MW-month

Monthly Refund June through December 2014

2,294.64 – 2,127.01 = 167.63 $/MW-month

– Refunds to long-term firm point-to-point and network transmission service customers have been calculated and included in invoices distributed in June 2015

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Overview of Rates, ATRR, and Loads

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Loads (divisor): Transmission Billing Demand

Average 12 CP (MW)2013

Projection2014

Projection2014 True-

Up

2014 True-Up/ 2014Projection Difference

2015 Projection

2015 Projection/

2014 ProjectionDifference

Part III – NITS (PacifiCorp)3YrAvg

8,461 8,460 8,531 +0.8% 8,537 +0.91%

Part III – NITS (Third-party)3YrAvg

101 115 109 -5.2% 134 + 16.52%

Other Service 3 Yr Avg

830 878 923 +5.2% 920 + 4.78%

Part II – LT PTP (PacifiCorp) 3,339 2,679 2,679 0.0% 2,474 - 7.65%

Part II – LT PTP (Third-party) 741 961 958 -0.3% 953 -0.83%

Behind-the-Meter 174 257 269 + 4.7% 263 + 2.33%

1% growth (Projection only) 94 97 n/a n/m 98 +1.0%

Divisor (MW) 13740 13,447 13,469 + 0.16% 13,379 - 0.50%

2014 True-Up Loads:- Actual 2014 load was in line with the June 2014 Projection- Largest component, PacifiCorp NITS, grew less than 1%2015 Projection:- Largest change in PacifiCorp LT PTP loads (decreased 205 MW) due to termination of

long-term contracts- Partially offset by increases in PacifiCorp and third-party NITS and Other Service

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Formula Rate Fixed Assumptions

Major fixed assumptions in the Formula:

- Stated ROE of 9.8%

- Incentive ROE of 0.5% applied to Energy Gateway projects

- BoY-EoY or 13-month averages for the true-up and end-of-year balances for the projection of some ATRR components (e.g., Transmission PIS)

- Equity Ratio is capped at 53%

- Allocators used to calculate certain transmission-related expenses

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Allocators2014

Projection2014 True-

Up2014 True-Up/2014 Projection

(percent change)

2015 Projection

2015 Projection/2014 Projection

Difference(percent change)

Wages and Salaries Allocator 7.1869% 7.9491% +10.60% 7.9491% +10.60%

Gross Plant Allocator 22.2296% 21.6787% -2.48% 22.7844% +2.50%

Net Plant Allocator 24.8693% 24.0662% -3.23% 25.8486% +3.94%

Allocators have varying effects on the Formula rate inputs2014 True-Up • Gross Plant allocator decreased because Transmission Gross Plant

grew slower than Electric Plant in Service (0.18% vs 2.73%) • Net Plant allocator decreased primarily because accumulated

depreciation grew faster than additions to the total plant in the rate base 2015 Projection • Gross Plant and Net Plant allocators increased because Transmission

Net Plant grew faster than Electric Plant in Service

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Wage and Salary Allocator

2015 Projection 2014 True-Up Difference

Wage and Salary Allocator (line 5) 7.1869% 7.9490% +10.60%

The inputs are derived from the FERC Form No. 1 (page 354)Transmission-Operations labor changes:• Increased transmission cross charges for EMS SCADA project• Higher dispatch and control labor cost due to added personnel• Decreased labor cross charges from Transmission-Operations to other departments• Decreased capitalized labor due to lower capital project activities in 2014 vs. 2013Transmission-Maintenance labor changes:• Reduced labor charges to Transmission-Maintenance for journeyman power and delivery

maintenance labor cost

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Gross Revenue Requirement

50,971,859 10%

16,603,228 3%

100,621,952 19%

30,517,764 6%

234,348,620 44%

94,106,754 18%

2014 Projection49,891,074 

10%12,320,803 

2%

98,440,344 19%

29,628,047 6%

228,203,453 45%

91,108,173 18%

2014 True‐Up

49,891,074 9% 11,189,024 

2%

98,440,344 18%

31,822,263 6%

254,681,862 46%

101,761,146 19%

2015 Projection

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Investment Return: Rate Base - Net PP&E

Net PP&E

2014 True- Up: Net PP&E did not change significantly. The decrease was primarily attributable to higher accumulated depreciation, partially offset by higher allocated portion of general and intangible assets to transmission

($)2014

Projection 2014 True-Up

2014 True-Up/ 2014 Projection

Difference2015

Projection

2015 Projection/ 2014 Projection

Difference

+ Net PP&E (Line 32)

4,029,045,025 3,993,461,544 - 0.88% 4,365,682,551 + 8.36%

+ Adjustments (Line 51)

(946,659,781) (970,781,509) - 2.55% (992,281,460) - 4.82%

= Rate Base (Line 52)

3,082,385,244 3,022,680,034 - 1.94% 3,373,401,091 + 9.44%

Investment Return=Rate Base*Rate of ReturnRate Base (Line 52)

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Investment Return: Rate Base: Net PP&E (cont’d)

2015 Projection– Increase in Net PP&E primarily due to increase in Total Plant

in rate base (+7.69%), partially offset by increased Accumulated Depreciation and Amortization balances (+5.83%)

– Forecasted additions: Energy Gateway $340.8m Sigurd to Red Butte segment $4.42m incentive added for Energy Gateway transmission

projects– Other Transmission PIS

$38.4m Carbon plant system reinforcement $177.7m of multiple other large and small investments

originated to meet NERC standards and transmission contractual obligations

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Investment Return: Rate Base Adjustments

Accumulated Deferred Income Taxes (ADIT) net of FASB 106 and 109– Increased (i.e., more negative) ADIT adjustment in 2014 True-Up lowers rate

base versus 2014 Projection– Changes in ADIT are largely the result of normal activity over 2014

Plant additions in 2014 Tax bonus depreciation

($) 2014 Projection 2014 True-Up

2014 True-Up/ 2014 Projection Difference

2015Projection

2015 Projection/

2014 Projection Difference

ADIT (ln 33) (888,013,375) (916,062,424) - 3.16% (942,356,425) -6.12%

Network Upgrade (ln 50) (58,242,601) (55,262,724) +5.12% (52,282,848) +10.23%

Materials & Supplies (ln 46) 7,242,424 8,635,085 +19.23% 9,331,690 +28.85%

Other (7,646,229) (8,091,446) -5.82% (6,973,877) +8.79%

Total (946,659,781) (970,781,509) -2.55% (992,281,460) -4.82%

*Included in Other are adjustments for income tax credit, unfunded reserves and prepayments.

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Investment Return: Rate Base Adjustments (cont’d)

Network Upgrade Balance (Line 50):

– Decreased (i.e., less negative) Network Upgrade Balance lowers rate base versus 2014 Projection

– Decreased due to refunds of approximately $8.9 million for interconnection projects, offset by additional network upgrade construction costs of approximately $3.0 million

Materials & Supplies Allocated to Transmission (Line 46):

– Increased (i.e., more positive) materials and supplies expenses increases rate base versus 2014 Projection

– Increase is primarily due to increased construction materials and supplies balances

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Investment Return: ROR (Line 126)

2014 AnnualUpdate

2015 Annual Update

% change

Rate of Return 7.60% 7.55% -0.05%

Major driver for the decrease is the lower average cost of debt for 2014 vs. 2013

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Total Transmission O&M (Line 75)

($)2014

Projection2014 True-

Up

2014 True-Up/2014

ProjectionDifference

2015 Projection

2015 Projection

/2014Projection Difference

Transmission O&M (ln 56) 50,971,859 49,891,074 - 2.12% 49,891,074 - 2.12%

Allocated A&G expense (ln 66) 11,010,569 6,363,632 - 42.20% 5,058,993 -54.05%

Directly assigned A&G (ln 74) 5,592,659 5,957,171 +6.52% 6,130,031 +9.61%

Total Transmission O&M (ln 75) 67,575,087 62,211,877 -7.94% 61,080,098 -9.61%

Transmission O&M (Line 56)– The increase of $14.9m in Total Transmission ( Line 53) from 2014 Projection includes:

Reclassification of $5.5m of NERC, WECC and NTTG membership dues from FERC 930.2 (Misc. General Expenses) to FERC 561.8 (Reliability, Planning and Standards Development)

Reversal of $1.7m of CWIP balances for Wallula to McNary 230 KV line project previously recorded in FERC 573 (Maintenance of misc. transmission plant)

– Transmission O&M decreased ~$1.1 primarily due to higher adjustments for FERC 565 (Transmission by others) and ancillary service FERC accounts 561.0-561.5 (Schedule 1 accounts) which are then subtracted from total Transmission O&M expenses resulting in an overall decrease of expenses in the rate base.

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A&G Expenses Allocated to Transmission (Line 66)

– Major components of the $71.9m decrease (unallocated values shown) to Total A&G (Line 57): $59.6 million – Injuries and Damages (FERC 925) $5.1 million – Misc. General Expenses (FERC 930.2)

primarily due to reclassification of $5.5m of membership dues to FERC 561.8 account

$2.3 million – Outside Service Employed (FERC 923) due to lower legal consulting services

Decreases were partially offset by $ 4.7m more transferred Administrative Expenses (credit) (FERC 922)

– Adjustments to A&G (subtractions) Increases in Property Insurance (FERC 924) and Regulatory

Commission Expense (FERC 928) accounts, total $3.3 million increase in the adjustment (i.e., higher deduction from total A&G)

PBOP adjustment (line 58) decreased in the 2014 True - Up

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PBOP Expense Adjustment

2014 True-Up

2015 Projection

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Directly Assigned A&G Expenses (Line 69 + Line 74)

– These items are initially removed from A&G and only certain components or allocated portions are included in the formula

– Major components of increase: $0.3 million (Gross Plant allocated) in Property

Insurance (FERC 924) EIM-related regulatory commission expenses of

$443,995 (FERC 928)

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Depreciation Expense

– Depreciation expenses decreased across all three categories (transmission, general, and intangible)

– Depreciation expenses for transmission and general assets decreased due to lower recent depreciation study rates

– Amortization expenses for intangible assets decreased mainly due to extension of initial useful lives of software assets

($) 2014 Projection2014 True-Up/ 2015 Projection Difference

Transmission Depreciation and Amortization Expense

100,621,952 98,440,344 -2.17%

Transmission Depreciation Expense (Line 83)

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Revenue Credits

– Total revenue credits in the 2014 True-up increased by $8.8m over the 2014 Projection

– The increase is primarily due to higher short-term use of the system.

($) 2014 Projection2014 True-Up/ 2015 projection Difference

+ Rents (FERC 454) 5,465,020 5,389,263 - 1.39%

+ Other Rev. (FERC 456) 133,963,051 142,798,094 + 6.60%

= Total Revenue Credits 139,428,072 148,187,356 + 6.28%

Revenue Credits (Line 152)

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Schedule 1

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Schedule 1: Overview

* 2013 Actual loads

– Calculated on Appendix B Historical FERC Account 561 values are excluded from

transmission formula and recovered in Schedule 1

Actual load (Attachment 9b)

– Revenue requirement increased and load decreased—each of which alone drives rate higher

2014 Update 2015 Update Difference

Revenue Requirement ($) 8,626,105 10,425,712 + 20.86%

12 CP Demand (MW) 14,143* 13,469 - 4.76%

Schedule 1 rate ($/MW-year) 609.91 774.06 + 26.96%

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Schedule 1: Annual Revenue Requirement

($) 2014 Update 2015 Update Difference

(561.1) Load Dispatch – Reliability 0 0 n/m(561.2) Load Dispatch – Monitor and

Operate Transmission System 7,218,959 8,490,351 + 17.6%

(561.3) Load Dispatch – Transmission Service and Scheduling

0 0 n/m

(561.4) Scheduling, System Control and Dispatch Services 292,567 824,276 + 181.7%

(561.5) Reliability, Planning and Standards Development

1,114,579 1,111,085 -0.3%

Annual Revenue Requirement 8,626,105 10,425,712 + 20.9%

– FERC 561.2 increase due to- EMS SCADA project expenses - Higher dispatch and control labor cost due to added personnel- Lower capital surcharge and capitalized expenses

– FERC 561.4 increase due to EIM-related administrative fees

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Additional Information

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EIM cost

– Energy Imbalance Market (“EIM”) costs (see Enclosure 8) $994,615 capital cost allocated to Transmission

$653,303 (FERC 560, 561, and 569) in Transmission O&M

$443,995 (FERC 928) in Directly Assigned A&G

– Clarifications Details in Enclosure 8 for EIM-related charges should have

included additional expenses of $44,973 in FERC 560 and $30,973 in FERC 561 that were incurred after the project “go live” date. This results in $653,303 of total EIM-related expenses included in Transmission O&M (vs. $577,667 presented in Enclosure 8).

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Annual Review Procedures

– General Interested parties have 180 days after the Publication Date (May 15) to

serve reasonable information requests to the Transmission Provider for information and work papers supporting the Annual Update

An Interested Party shall have the right to make Preliminary and/or Formal Challenges pursuant to the Protocols

– Information requests Please submit information requests to the following email address:

datarequest@PacifiCorp.com

IntraLinks is the online workroom for information request and response postings

PacifiCorp will post on IntraLinks information requests within one business day of receipt

PacifiCorp will make a good faith effort to respond within 10 business days of receipt of such requests

PacifiCorp will post responses to information requests on IntraLinks

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2015 Annual Update Timeline

May

15

Apr

il 1

7

July

10

May

31

June

1

Nov

. 11

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PacifiCorp Transmission

President and CEOPat Reiten

VP, TransmissionRick Vail

VP, Major Project Delivery

Stuart Kelly

VP & General CounselSarah Edmonds

Dir, ComplianceColt Norrish

Mgr, Exec Support SvcsTonia Stratton

VP, System OperationsMark Sampson

VP, Div ControllerTodd Dinehart

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Transmission

VP, TransmissionRick Vail

Mgr., Transmission Scheduling Service

Brian McClelland

Dir., Transmission ServicesBrian Fritz

Mgr., Contract Admin & Transmission Services

Patience Kerchinsky

Dir., Transmission Planning & Capital InvestmentJack (JD) Podlesnik

Dir., Reliability StandardsFlo Hausler

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General Counsel, Transmission Policy & Strategy

VP & General Counsel Sarah Edmonds

Sr. CounselMary Ellen Stefanou

Mgr., Regulatory Policy & RatesShayleah LaBray

Sr. CounselPatrick Cannon

Transmission Regulatory Analyst

Lisa Harkins

Legal AssistantMorgan Herring

Transmission Market SpecialistChristine Kirsten

Sr. Planning Financial AnalystNatalia Bronner

Sr. Planning Financial AnalystEric Arzola

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Questions and Discussion