PacifiCorp Stakeholder Meeting on Regional

Independent System Operator Integration

January 27, 2016

1

2

Housekeeping matters

Welcome

Logistics and safety moment

Introductions

Agenda

3

Regional ISO

Stakeholder Process

4

Regional ISO status

California SB 350, signed into law October 7, 2015, established a pathway for

regional ISO expansion and governance

PacifiCorp and the ISO announced results of a regional integration gross benefits

study October 13, 2015 study report available on the ISO and PacifiCorp web sites

http://www.caiso.com/Documents/StudyBenefits-PacifiCorp-ISOIntegration.pdf

technical appendix describing the study methodology is also available:

http://www.caiso.com/Documents/Study-TechnicalAppendix-Benefits-PacifiCorp-ISOIntegration.PDF

Stakeholder explanatory session on gross benefits held October 16, 2015 audio of session available:

http://www.caiso.com/informed/Pages/RegionalEnergyMarket/BenefitsofaRegionalEnergyMarket.aspx

Study results demonstrate sufficient benefits to continue exploring integration ISO and PacifiCorp extended the Memorandum of Understanding to further explore costs and other

requirements to achieve benefits of integration and proceed in the best interest of customers

5

Regional ISO drivers and overview

PacifiCorp and the ISO entered into a Memorandum of Understanding in April 2015

to explore potential benefits and costs of creating a regional ISO.

Regional market integration efforts are aimed at:

reducing customer costs

enhancing coordination and reliability of western electric networks

facilitating renewable energy resource integration

reducing emissions

enhancing regional planning and expansion

Successful market integration will require:

approval by PacifiCorp state regulatory bodies and the FERC

changes in California state statute to amend governance

approval by the FERC of PacifiCorp and ISO tariff changes on a range of market

process issues

6

ISO timeline for regional integration activities

7

Gross benefits study overview

Integration of PacifiCorp and ISO systems results in significant benefits for both

PacifiCorp and ISO customers over 20-year period of 2020-2039:

Savings in 2015$ Billions and incremental to EIM benefits

The study quantifies benefits in four areas:

1. More efficient dispatch and commitment

2. Lower peak capacity savings

3. More efficient over-generation management

4. Renewable procurement savings

Area Low High

PacifiCorp $1.6B $2.3B

ISO $1.8B $6.8B

Combined Benefit: $3.4B $9.1B

8

Key study results

0

100

200

300

400

500

600

700

800

900

1,000

LowScenario

HighScenario

LowScenario

HighScenario

2024 2030

An

nu

al C

ost

Sav

ings

(M

illio

n 2

015$

)

ISO

Resource Procurement Savings

More Efficient Overgeneration Management

Lower Peak Capacity Needs

0

100

200

300

400

500

600

700

800

900

1,000

LowScenario

HighScenario

LowScenario

HighScenario

2024 2030

An

nu

al C

ost

Sav

ings

(M

illio

n 2

015$

)

PacifiCorp

Resource Procurement Savings

More Efficient Overgeneration Management

Lower Peak Capacity Needs

More Efficient Unit Commitment and Dispatch

61

31

61

31

121

65

138

65

138

691

Total:$92

Total:$213

Total:$203

Total:$894 ISO

0

100

200

300

400

500

600

700

800

900

1,000

LowScenario

HighScenario

LowScenario

HighScenario

2024 2030

An

nu

al C

ost

Sav

ings

(M

illio

n 2

015$

)

ISO

Resource Procurement Savings

More Efficient Overgeneration Management

Lower Peak Capacity Needs

0

100

200

300

400

500

600

700

800

900

1,000

LowScenario

HighScenario

LowScenario

HighScenario

2024 2030

An

nu

al C

ost

Sav

ings

(M

illio

n 2

015$

)

PacifiCorp

Resource Procurement Savings

More Efficient Overgeneration Management

Lower Peak Capacity Needs

More Efficient Unit Commitment and Dispatch

3131

3117

28

2525

46 36

138

54

138

54

Total:$62

Total:$122

Total:$199

Total:$271

PacifiCorp

Annual Cost Savings (Million 2015$)

9

Regional ISO next steps

The ISO will conduct stakeholder initiatives over the next two years to determine policy

changes and cost allocation for integration

Tariff changes developed through stakeholder processes and will require ISO Board and

FERC approval

PacifiCorp is developing a stakeholder schedule that compliments and supports the ISO

stakeholder process

PacifiCorp will seek regulatory approvals from all six states where its serves retail

customers, as well as from FERC

Full integration not targeted to occur prior to 2019

10

ISO stakeholder initiatives timeline

See Stakeholder Initiative Catalog for 2016 and Roadmap

See also ISO Stakeholder Processes

Initiative Planned start to

process

Regional Transmission Access Charge Structure In progress

Resource Adequacy Rules In progress

Regional Integration - CA GHG Compliance February 2016

Metering Rules Update February 2016

Full Network Model Enhancements July 2016

11

Regional ISO stakeholder process schedule of dates

Transmission Access Charge Options

February 8 Publish straw proposal

March 1 Stakeholder meeting to discuss straw proposal (Location: ISO, Folsom)

March 10 Written comments due on straw proposal

April 7 Publish draft final proposal

April 21 Stakeholder meeting to discuss draft final proposal (Location: TBD)

May 10 Written comments due on draft final proposal

Related materials available on initiative webpage at

http://www.caiso.com/informed/Pages/StakeholderProcesses/TransmissionAccessChargeOptions.aspx

Regional Resource Adequacy

February 17 Publish straw proposal

March 2 Stakeholder meeting to discuss straw proposal (Location: ISO, Folsom)

March 11 Written comments due on straw proposal

March 23 Stakeholder working group to discuss straw proposal topics (Location: TBD)

May 4 Publish draft final proposal

May 12 Stakeholder meeting to discuss draft final proposal (Location: ISO, Folsom)

May 23 Written comments due on draft final proposal

Related materials available on initiative webpage at

http://www.caiso.com/informed/Pages/StakeholderProcesses/RegionalResourceAdequacy.aspx

12

Date Time Subject

February 2 2:00 – 2:30 ISO Regional Integration Update Call (semi-monthly)

February 10 2:00 – 4:00 PacifiCorp/ISO Market Governance Issues

February 11 2:00 – 3:00 PacifiCorp Regional ISO Regulatory Stakeholder Call (monthly)

February 16 2:00 – 2:30 ISO Regional Integration Update Call (semi-monthly)

March 1 10:00 – 3:00 ISO Transmission Access Charge Options straw proposal

March 2 10:00 – 3:00 ISO Regional Resource Adequacy straw proposal

March 10 2:00 – 3:00 PacifiCorp Regional ISO Regulatory Stakeholder Call (monthly)

March 15 2:00 – 2:30 ISO Regional Integration Update Call (semi-monthly)

March 23 TBD ISO Regional Resource Adequacy Working Group straw proposal

April 5 2:00 – 2:30 ISO Regional Integration Update Call (semi-monthly)

April 14 2:00 – 3:00 PacifiCorp Regional ISO Regulatory Stakeholder Call (monthly)

April 19 2:00 – 2:30 ISO Regional Integration Update Call (semi-monthly)

April 21 TBD ISO Transmission Access Charge Options draft final proposal

May 12 TBD ISO Regional Resource Adequacy draft final proposal

Upcoming stakeholder meetings

13

PacifiCorp contracts

Affiliate 11%

Third-Party 89%

Agreement Share (Contract Count)

Affiliate Contracts are agreements between PacifiCorp Transmission and another

PacifiCorp entity (e.g., Pacific Power, Rocky Mountain Power)

Third-Party Contracts are agreements with entities that are not affiliated with PacifiCorp

Affiliate 85%

Third-Party 15%

Agreement Share (Average 12CP Demand)

Current FERC Jurisdictional Transmission Contracts

14

PacifiCorp contracts (continued)

Current FERC Jurisdictional Transmission Contracts

LGIA 25% SGIA

5%

STF/NF 3%

LTF 41%

NITSA 2%

Other 24%

PacifiCorp Affiliate Service Agreements

RS 2%

SA 98%

Total PacifiCorp Affiliate Agreements

Rate Schedules (RS) and

Service Agreements (SA)

15

PacifiCorp contracts (continued)

Current FERC Jurisdictional Transmission Contracts

SA 69%

RS 31%

PacifiCorp Third-Party Contracts

Large Generation Interconnection

15%

Small Generation Interconnection

8%

Short Term Firm Point to Point

47%

Resale 5%

Long Term Firm Point to Point

12%

Network Integration

Service 4% Other

9%

PacifiCorp OATT Third-Party Contracts

16

System overview - PacifiCorp

One of the largest privately held transmission

systems in the United States over 16,300 miles of transmission lines

spanning 10 states over 900 substations – transmission &

distribution 12,685 MW record peak demand (June

29, 2015) 10,964 MW of power generation

capacity (net capacity) 70 million megawatt-hours of electricity

delivered annually over 1.8 million customers across 6

states

Two balancing authority areas (PACE and

PACW)

Operated as an integrated system through

agreements and scheduling practices

Interconnected with: over 80 generating plants 13 adjacent balancing authority areas at

over 170 interconnection points

17

PacifiCorp’s transmission system

18

Overview of existing ISO market and planning processes

Topics

ISO participant types and definitions

Fundamental ISO market concepts

ISO provides Balancing Authority functions via its markets

Bilateral energy contracts in the ISO market system

Provisions relevant for load-serving entities

Transmission planning process

19

ISO participant types

Scheduling Coordinator (SC) – an entity authorized to buy and sell

power and schedule transmission use in the ISO markets

Participating Transmission Owner (Participating TO) – a

transmission owner that has placed its transmission assets and

entitlements under the ISO’s operational control

Participating Generator (PG) – a resource providing energy or

ancillary services through a SC (generators, dynamic resources,

pseudo-ties, renewables, etc.)

Participating Load (PL) – a load providing energy or ancillary

services as curtailable demand through a SC

Demand response (DR) – a load or aggregation of loads providing

energy or ancillary services as demand reduction through a SC

20

ISO participant types (continued)

Eligible Intermittent Resource (EIR) – a variable energy resource (wind or

solar) that participates in the ISO market through a SC and whose expected

output is forecasted for market purposes by ISO

Load Serving Entity (LSE) – an entity that serves retail end users within the

ISO balancing authority area

Investor Owned Utility (IOU) – a private utility company owned by

shareholders

Municipal Utility (Muni) – a public utility that is owned by the customers it

serves

Metered Subsystem (MSS) – a muni that wants to retain its vertically

integrated utility within the ISO balancing authority area

Utility Distribution Company (UDC) – a distribution company connected

to the ISO controlled grid that serves load

21

Fundamental ISO market concepts

1. The ISO market structure simultaneously performs transmission scheduling, congestion management, reliable grid operation and wholesale spot energy trading.

2. Locational Marginal Pricing (LMP) aligns market energy prices with grid topology and current conditions.

3. Locational Marginal Prices (LMPs) consist of three components for energy, congestion and losses.

The sum of the three components at any given pricing node (PNode or transmission-distribution substation) is the nodal LMP.

In any given time interval, the energy component is the same system-wide => differences in LMPs across the grid reflect congestion & losses.

4. The basic settlement principle in the ISO market is:

Entities that inject energy into the grid (generators, importers) are paid the LMP at the injection location.

Entities that withdraw energy from the grid (LSEs, exporters) are charged the LMP at the withdrawal location.

22

ISO provides balancing authority functions via markets

Day-ahead and real-time markets perform essential BA functions

schedule use of the grid by suppliers and load-serving entities

maintain supply-demand balance and reliable grid operation

manage congestion to ensure schedules are feasible

ISO market settlements manage and clear transactions related to

grid and market use

ISO invoices grid and market users for transmission service and

market energy transactions

Invoices include TAC charges, which ISO redistributes to

Participating TOs

ISO charges TAC to wholesale load & exports; state regulators decide

how to pass TAC charges to retail customers

ISO maintains financially neutral position, except for Grid

Management Charge (GMC) to pay for ISO services

23

Bilateral energy contracts in the ISO market system

Bilateral energy contracts between suppliers and LSEs are not

visible to the ISO

However, 100% of energy delivered over the ISO grid must be

scheduled via the market

The market is the vehicle for scheduling transmission service

Parties to bilateral energy trades may submit economic bids

(prices & quantities) or self-schedules (quantities only), or

both, to align best with their contractual arrangements

A supplier whose contract requires energy supply from a specific

resource will likely self-schedule that resource.

A supplier whose contract does not require supply from a specific

resource may serve that contract at least cost through the use of economic

bids.

An LSE who is party to a bilateral energy trade will generally self-

schedule the load served by the trade.

24

Provisions relevant for load-serving entities (LSEs)

Transmission Access Charge (TAC)

mechanism for Participating TOs to recover their costs of owning, maintaining

and operating ISO grid facilities

FERC-approved Transmission Revenue Requirements (TRR) are recovered

through per-MWh rate paid by gross internal load and exports

current TAC rate structure consists of

– regional postage stamp rate for > 200 kV facilities

– local Participating TO-specific rates for < 200 kV facilities

existing contracts continue paying contract prices

Resource Adequacy

each LSE must demonstrate sufficient capacity to meet its pro rata share of

coincident peak demand plus reserve margin

before start of calendar year – demonstrate 90% of monthly peak demand plus

local capacity needed for constrained load pockets

45 days before start of each month – demonstrate 115% of monthly peak

demand

25

Provisions relevant for LSEs (continued)

Congestion Revenue Rights (CRR)

aka “financial transmission rights”

provide shares of congestion revenues collected through the ISO markets

enable LSEs to hedge market congestion costs between supply locations and

load locations

allocated at no charge to LSEs as entitlement for paying TAC

LSE shares based on exposure to market congestion costs => volume of load

and locations of supply sources

available for purchase by all parties through auction

Maximum Import Capability (MIC)

import capacity available to LSEs for import of resource adequacy capacity

on each import path

total amount available is based on simultaneous net import capability of

whole ISO system

allocated annually to LSEs

26

The ISO’s comprehensive transmission planning process

The ISO’s annual TPP for the ISO region is designed to:

Identify needs for reinforcement of the transmission system for a broad

range of purposes including:

reliability needs

policy-driven needs

economically driven needs

Recommend preferred solutions to meet identified needs, considering

viable options including non-transmission solutions

Coordinate with other fundamental processes including

resource planning by state agencies and utilities

generator interconnection processes

Provide engineering analysis to comply with federal mandatory planning

standards and other technical study needs

27

The ISO’s Participating TOs have major responsibilities in the TPP

Development of base cases and contingency files – due approximately

in May of each year

Conduct their own reliability analysis (including short circuit analysis)

– due July of each year

Review ISO’s preliminary reliability results and submit reliability

proposals to mitigate identified reliability issues

Provide detailed information on new Special Protection Systems

following the finalization of the Board-Approved Transmission Plan

Coordinate on NERC, WECC and ISO Standards throughout the year

the ISO is the NERC-registered Planning Coordinator

the Transmission Owners are NERC-registered Transmission Planners

28

The ISO’s TPP is coordinated with California state processes

CEC creates demand forecast

CPUC assesses resource needs

ISO creates comprehensive transmission plan

CPUC creates procurement plan

1

2

3

4

IOUs

Final plan authorizes

procurement

Results feed into next biennial cycle

29

Transmission upgrade approval process

ISO Management approves projects with capital cost of $50 million or less

The Final Draft Transmission Plan is presented to the ISO Governing Board

for approval – and specific approval of any projects not approved by

Management

ISO then posts the Board Approved Comprehensive Transmission Plan and

initiates development of transmission solutions

regional facilities (> 200 kV) may be eligible for competitive solicitation

not eligible are additions to existing Participating TO facilities and all < 200 kV;

these are all assigned to relevant Participating TO to build and own

ISO coordinates with CPUC procurement process to procure non-transmission

solutions

CPUC is the authority that reviews and approves project routing and

environmental compliance

ISO makes the Plan available to neighboring transmission providers,

interconnected balancing authority areas and regional planning groups

30

ISO and neighboring regions filed Order 1000 interregional

planning coordination framework approved by FERC

NTTG Northern Tier Transmission

Group

WestConnect

Footprint

COLUMBIAGRID

ISO California

Independent System

Operator

SIERRA CCPG

Colorado

Coordinated

Planning

Group

SWAT Southwest Area

Transmission

• Interregional coordination

– annual exchange of information

– annual public interregional coordination meeting

• Joint evaluation of interregional transmission projects

– biennial cycle

– projects must be submitted no later than March 31st of any even-numbered year

• Interregional cost allocation

– each region determines (1) if project meets any regional needs, and (2) if project is more cost effective or efficient than regional solution(s)

– costs shared in proportion to each region’s share of total benefits

31

Customer service integration issues – contracts overview

Existing contracts rights - what are they? and how does ISO treat them?

terminology

high-level tariff requirements

Customer service transition, review of service plans, encumbrances and entitlements

OATT/legacy agreements with internal and external resources/load

load interconnection agreements

generator interconnection agreements

long-term power purchase agreements

translating existing contracts into instructions

generator interconnection study process

new resource implementation process

32

Existing contract terminology

Encumbrance - A legal restriction or covenant binding on a Participating TO that affects

the operation of any transmission lines or associated facilities and which the ISO needs to

take into account in exercising Operational Control over such transmission lines or

associated facilities if the Participating TO is not to risk incurring significant liability.

Entitlement - The right of a Participating TO obtained through contract or other means to

use another entity’s transmission facilities for the transmission of Energy.

Existing Contracts (ETC)- The contracts which grant transmission service rights

(including any contracts entered into pursuant to such contracts) as may be amended in

accordance with their terms or by agreement between the parties thereto from time to

time.

Existing Rights - The right of a Participating TO obtained through contract or other

means to use another entity’s transmission facilities for the transmission of Energy.

Non-Participating TO – A party that does not turn over operational control of their

transmission to the ISO

33

ISO tariff requirements for existing contracts

Existing Contracts will continue to be honored for the duration of those contracts.

scheduling, curtailment, assignment and other aspects of transmission system usage

PacifiCorp is required to attempt to negotiate changes to Existing Contracts to align

the contract’s scheduling and operating provisions with the ISO’s scheduling and

operational procedures, rules and protocols, and minimize costs of administering the

contract while preserving their financial rights and obligations.

PacifiCorp is required to ensure that Existing Contracts do not pay twice for

transmission services.

All revenue received from Existing Contracts is a credit to the ISO access charge

Non-Participating TO right to use and ownership of its facilities shall remain

unchanged.

PacifiCorp shall provide valid ETC Self-Schedules for holders of Existing Rights, or a

holder of Existing Rights may obtain its own Scheduling Coordinator.

ETC Self-Schedules need to meet the scheduling and operational requirements to

receive special payment provisions.

The ISO will have no role in interpreting Existing Contracts.

34

ISO northern bulk transmission system

35

Sample of existing ISO entitlement rights

Path Import (MW) Export (MW)

Gondor 60 100

Mona 450 900

Intermountain Power Project 500 1150

Mead – Adelanto 600 80

Summit 120 100

36

PAC/ISO OATT contract correlation

PacifiCorp ISO

Provided OATT Service

Firm / Non-Firm / Network /

Point-to-Point

Scheduling Coordinator Agreement (SCA)

- All service is firm / network

Provided Non-OATT Service Encumbrance until agreement terminated

Taken OATT Service in another BA Entitlement – provides scheduling rights

for ISO market transactions

Taken Non-OATT Service in another BA –

includes resource specific lines and

stranded load service needed from other

BA

Entitlement – provides scheduling rights

for ISO market transactions

37

PAC/ISO contract correlation (continued)

PacifiCorp ISO

Interconnection agreement - BA Adjacent Balancing Authority Operating

Agreement (ABAOA) – Participating TO

transmission interconnection agreements

continue

Interconnection agreement – Generator Generator Interconnection Agreement

(LGIA or SGIA) – Participating TO does

not have another agreement

Interconnection agreement – load NA – Participating TO responsibility

Exchange agreement NA

Boundary Meter Meter Service Agreement for ISO Metered

Entity (MSAISOME)

Construction; O&M NA

Remedial Action Scheme Operating procedure

Emergency service – including stranded

load PAC serves

ABAOA

38

Transmission right and transmission curtailment (TRTC)

PAC and the existing right holder will develop TRTC instructions

existing scheduling and curtailment priorities

minimal burden to Participating TO, Existing Right holder and ISO operational polices and

procedures

to the extent possible, imposes no additional financial burden on Participating TO or

Existing Right holder

capacity not used by Existing Right holder will be made available to market participants

ISO does not interpret or underwrite the economics of the Existing Contract

any disputes with TRTC instructions will be resolved using the dispute resolution

provisions of the Existing Contract

TRTC content includes

– contract reference numbers

– timing of the instructions – day-ahead, hour-ahead, etc.

– point(s) of receipt / Point(s) of delivery

– capacity

– curtailment implementation – pro rata, priority, etc.

– forecasted annual usage patterns

– self-provide ancillary services

– other special considerations

39

Generator interconnection study process

ISO queue open April 1 – 30, annually

Study is in two phases Phase I and II (~ 2 years)

Deliverability Assessment

on-peak deliverability assessment for projects requesting full or partial capacity

deliverability status

off-peak deliverability assessment for information Only

Reliability Assessment Scope

power flow study (thermal loading)

voltage assessment (steady state and transient) and reactive power deficiency assessment

post transient stability study

transient stability study

short circuit duty study

Study results include

project impacts to the transmission systems

facilities required to interconnect the project

upgrades required to mitigate adverse impacts and deliver power to the grid

estimated costs and construction time for IFs and NUs

potential affected system impacts and coordination

40

Generator Interconnection Study process (continued)

Generator interconnection agreement

tender 30 days after Phase II results

negotiation – 120 days

execution

Queue Management

reports – quarterly, then monthly 12 months prior to sync

modifications

suspensions

contract issues

testing options

limited operation studies

41

New resource implementation

Structured process handles new generation to the grid

7 months prior to sync – contact ISO

provide technical information – PSLF, communication block diagrams, single- and three-

line drawings, meter and telemetry

4 months prior to sync

execute regulatory contracts, model testing and forecasting information

30 calendar days prior to sync

declare Scheduling Coordinator, provide resource data template, and meter certification

10 calendar days prior to sync

trial operations schedule and meter and telemetry end-to-end testing

1 calendar day prior to sync

confirm sync,

Unit/capacity synchronization - begin testing

Commercial operation

42

Next steps

Meeting targeted for June 2016 – “deeper dive” into contracts

Discuss specific contract terms and how those existing rights are proposed to be

translated using examples

Transmission service for generation

Transmission service for load

Wheeling transmission service

Interconnection service for generation

Stranded load in N-1 contingencies

Emergency assistance

Balancing Area interconnection

What agreements won’t change

Construction

Operation and Maintenance

Interconnection service for load

Protection