2013 IRP Advisory Group Meeting Demand-Side Resource Potentials Gas Resource Needs & Alternatives Colstrip

November 15, 2012

Today’s Agenda

9:00 – 9:15 am: Hello and Welcome

9:15 – 9:30 am: Introductions

9:30 – 9:45 am: Process Check-In

9:45 – 11:15 am: Demand Side Resource Potentials

11:15 – 11:30 am: Gas Resource Needs

11:30 – 12:30 pm: Gas Resource Alternatives

12:00 – 1:00 pm: Lunch & Electric Acquisition Update

1:00 – 2:30 pm: Colstrip

2:30 – 2:50 pm: Wrap-Up & Next Steps

2

Safety Moment

According to the Centers for Disease Control, the most common causes of longterm disability are arthritis and musculoskeletal problems. They make up about 1/3 of all disability cases, and bad backs fall into this category. To help keep your back healthy for years to come, proper lifting techniques are essential.

3

Integrated Resource PlanningWAC 480-100-238 Integrated resource planning.

(1) Purpose. Each electric utility regulated by the commission has the responsibility to meet its system demand with a least cost mix of energy supply resources and conservation. In furtherance of that responsibility, each electric utility must develop an "integrated resource plan."

(2) (a) "Integrated resource plan" or "plan" means a plan describing the mix of energy supply resources and conservation that will meet current and future needs at the lowest reasonable cost to the utility and its ratepayers.

(2) (b) "Lowest reasonable cost" means the lowest cost mix of resources determined through a detailed and consistent analysis of a wide range of commercially available sources. At a minimum, this analysis must consider resource cost, market-volatility risks, demand-side resource uncertainties, resource dispatchability, resource effect on system operation, the risks imposed on ratepayers, public policies regarding resource preference adopted by Washington state or the federal government and the cost of risks associated with environmental effects including emissions of carbon dioxide.

( )_____________

Regulatory Compliance

Customer Needs

Stak

ehol

ders

Market O

utlook

5

Mar 6th 2012 – Kickoff Meeting

Big Picture Framing,

Began discussion on WUTC letter regarding Colstrip analysis

May 1st 2012 – Framing & Draft Work Plan

Discussion on scenarios,

Discussion of some Colstrip analysis isssues,

PSE agrees to model the societal costs of CO2 in addition to the CO2 tax approach.

June 21st 2012 – Framing & Into Assumptions

More discussion on scenarios,

Shared draft CO2 costs/prices, draft gas prices, draft base case power prices.

Sep 6th 2012 – Market Assumptions & Operational Flexibility Approach

Review power prices for all scenarios,

Assumption and results of market power price analysis,

Analyzing electric operational flexibility—physical and financial—and approach to incorporate into 2013 IRP.

Advisory Group Meeting Summary to Date

6

Two Meetings on Scenarios/Sensitivities

Looking at various Colstrip sensitivities

Looking at CO2 costs as a societal costs as well as a carbon cost and as a tax

New Questions for the IRP

Flexibility needs

Availability of the Regional Surplus

Build Constraints

Transmission considerations

Future of Colstrip

Showed early assumptions

Gas Prices

CO2 Cost/Prices

Electric Prices Incl. Impact of Colstrip Retirement on Mid-C

IRP Advisory Group Meeting Highlights

7

2013 IRP: DRAFT Scenarios & SensitivitiesScenarios: 4 Complete Possible Futures

Base Case: Mid Growth, Mid Gas Price, No New CO2 Prices

Green World: High Growth, High Gas Price, Mid CO2 Prices

Low: Low Growth, Low Gas Price, No New CO2 Prices

High: High Growth, High Gas Price, No New CO2 Prices

Sensitivities: 17+ What if/All Else Equals???

2 Base + CO2 Costs: High/Low

2-3 No Colstrips: Sold/Retired

2 Gas Price Extremes: Very High & Very Low Gas Prices

DSR Avoided Capacity Value: Physical & Financial

Accelerated Demand-Side Resources

Transportation Load: Electric and Gas

Tax Incentives for Renewables

Timing of Regional Surplus

Build Constraints

Fuel Supply Constraints8

High+Mid CO2

-------__

Scenario MatrixScenario Gas Price Regional

LoadCO2 Plant Retirement

Base Reference Reference Reference ReferenceLow Low Low Reference ReferenceHigh High High Reference ReferenceGreen World High High Price (Mid) Retire Nuclear & CoalBase + CO2 High Reference Reference Societal (High) ReferenceBase + CO2 Low Reference Reference Societal (Low) ReferenceColstrip Retire Reference Reference Reference Retire Colstrip 2025Very High Gas Very High Reference Reference ReferenceVery Low Gas Very Low Reference Reference Reference

9

High+Mid CO2

10

$/M

MB

tu

4.205.81

8.08

9.9611.57

3.174.20

6.06

7.81

9.98

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

Very Low Gas Low Gas Base High Gas Very High Gas

$/MMBtu

Compare Draft 2013 IRP Levelized  Gas Prices(Sumas Hub, 20 year levelized , nominal $, 7/09/12 update)  

2011 IRP2013 IRP

CO2 Cost/Price Forecasts

Avg Annual Mid-C Price Forecast: Summary

0

20

40

60

80

100

120

140

160

180

2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033

Nom

inal $/M

Wh

Annual Average Mid‐C Power Price (Nominal $/MWh)

Base + High CO2

Green World

Very High Gas

High

Base + Low CO2

Colstrip Retire 2025

Base

Low

Very Low Gas

12

Hi + Mid CO2 Price

Regulatory Compliance

Customer Needs

Stak

ehol

ders

Market O

utlook

13

Demand-Side Resource Potentials

Cadmus Presentation

14

Gas Portfolio Needs & Resource Alternatives

November 15, 2012

Jay Jacobsen, Gurvinder Singh & Bill Donahue

Agenda – Gas Resource Needs and Alternatives

Introduction

Needs

Peak Capacity

Annual Load

Resource Alternatives

DSR

Supply – Pipeline and Storage

LNG Peak Shaving

Q & A

16

17

-

200.0

400.0

600.0

800.0

1,000.0

1,200.0

1,400.0

1,600.0

MD

th /

day

Peak Load/Resource Balance - Gas Sales Portfolio(Draft 11/15/2012)

Total Jackson Prairie & Redelivery Service Plymouth LNG & Redelivery ServiceOn System Total NWP Firm Transport (TF-1)Additional NWP Firm Transport Available w/ Renewals F2012 Base Forecast w/ 2012-13 DSR Only

13

195323

99

18

0

50

100

150

200

250

300

MD

th / d

ay

Peak Load/Resource Balance - Gas for Power Portfolio(Note: Existing Generation Only - Draft 11/15/12)

Total Jackson Prairie (no redelivery service) NWP Year-Round Transport (TF-1)Additional NWP Firm Transport Available w/ Renewals Existing Generation Peak Demand

-5

19

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

Annu

al V

olum

e (M

Dth

)

Weather Normalized Historical

Base

2005‐11 Historical Loads & F2012 IRP Forecast Scenario(Firm + Interruptible excluding transport, includes 2012-13 DSR)

DSR Resource Alternatives

Eligible Customers, Loads, End- Uses, DSR Measures

Technical Potential

Achievable Technical Potential

DSR Bundle

A2

DSR Bundle

A3

DSR Bundle

B1 … …

Customer Forecast

Load Forecast

Baseline EUC

System Load Curve

Fuel Shares

Appliance Saturation

Measure Characteristics

End-use Load Shapes

Market Constraint Factors

Measure Costs & Administrative Expenses Divide into Cost Groups

Portfolio Optimization Model - SENDOUT®

Sub-divide into market sectors and weather-sensitive measures

DSR Bundle

A1

…DSR Bundles

D, E, F,G

DSR Bundle

B2

DSR Bundle

C1

DSR Bundle

C2

Bundles 2011 IRP vs. 2013 IRP

21

Bundle 2011 IRP Bundle 2013 IRPA ($99.00) to $0.45 A1 ($99.00) to $0.22

B $0.45 to $0.70 A2 $0.22 to $0.30

C $0.70 to $0.95 A3 $0.30 to $0.45

D $0.95 to $1.20 B1 $0.45 to $0.55

E $1.20 to $1.50 B2 $0.55 to $0.70

F $1.50 to $2.00 C1 $0.70 to $0.85

G $2.00 to $2.50 C2 $0.85 ‐

$0.95

H $2.50 to $99.00 D $0.95 to $1.20

E $1.20 to $1.50

F $1.50 to $2.00

G $2.00 to $99.00

Achievable Technical Potentials

Bundle Price Cut-Offs for Bundles2013 IRP Annual MDth ATP1

2014 2033

A1 ($99.00) to $0.22 83.0  3,361.3 

A2 $0.22 to $0.30 168.0  3,406.6 

A3 $0.30 to $0.45 13.2  377.4 

B1 $0.45 to $0.55 2.3  53.3 

B2 $0.55 to $0.70 9.8  254.7 

C1 $0.70 to $0.85 11.9  329.1 

C2 $0.85 ‐

$0.95 4.5  96.1 

D $0.95 to $1.20 25.7  887.3 

E $1.20 to $1.50 128.5  2,634.6 

F $1.50 to $2.00 38.8  1,105.5 

G $2.00 to $99.00 583.4  12,817.0 

22Notes: 1. ATP = Achievable Technical Potential

Gas DSR Ramp Rates

23

Three ramp rates will be tested:

10-year ramp of discretionary measures

20-year ramp of discretionary measures

Delayed 10-year ramp of discretionary measures

Regional Transportation Map

24

Pipeline Alternatives

25

Alternative From/ToCapacity Demand

($/Dth/Day)

Variable Commodity

($/Dth)

Fuel Use (%) Comments

Vintage NWP Rockies & Sumas to PSE 0.41 0.03 1.4 No additional vintage capacity available

Expansion of NWP Sumas to PSE 0.50 0.03 1.9 Prospective project, estimated project cost

Westcoast (T-south) Station 2 to Sumas 0.42 0.01 1.6 30% of Westcoast capacity is uncontracted

Westcoast (T-north) Prod. fields to Station 2 0.13 0.01 1 Needed in conjunction with Aitken Creek storage

Fortis BC/Spectra KORP

Foothills to Sumas (Bi- directional) 0.44 0 0 Prospective project

NGTL (Nova) Pipeline AECO to Alberta/BC border 0.17 0 0 Uncontracted capacity is available

Foothills Pipeline BC Border to Kingsgate 0.097 0 1.1 Uncontracted capacity is available

GTN Pipeline Kingsgate to Stanfield 0.177 0.004 1.4 Uncontracted capacity is available

Palomar/Blue Bridge Stanfield to PSE 0.80 0.005 2.0 Prospective project, estimated project cost

Ruby Pipeline Rockies to Malin 1.14 0.01 0Published tariff is $1.14 but discounted rates are expected to be available for

several years

GTN "Backhaul" Malin to Stanfield 0.21 0.005 0 Uncontracted capacity is available

Storage AlternativesAlternative

Storage Capacity

(MDth)

Max. With.

Capacity (MDth/day)

Days of Full With.

(days)

Max. Injection Capacity

(MDth/day)

Capacity Demand

($/Dth/mo)

Delivery Demand

($/Dth/mo)

Inj. Rate

($/Dth)

With. Rate

($/Dth)

Fuel Use (%)

Comments

Recent Jackson Prairie

Expansion2,184 104 21 52 0.106 1.234 - - 0.58 No additional JP

expansions planned

PSE LNG Project (PSE

portion)300 30 10 1.5 ? ? ? ? ?

Prospective project, estimated size and

costs

LNG Peak Gas Supply 200 20 10 - ? ? ? ? ?

Prospective project, estimated size and

costs

Mist Expansion 1000 50 20 20 - - - - -Prospective project, estimated size and costs, confidential

Clay Basin 4,000 33 120 26 0.024 2.85 0.011 0.018 1.9Existing project,

released capacity available in 2018

Ryckman Creek

(Peregrine)- 40 101 - - - - - -

Existing project, estimated size and costs, confidential

Aitken Creek - 40 150 - - - - - - Existing project - capacity available

26

27

LNG in PSE Service Territory

PSE is considering development of an LNG project to provide fuel for the natural gas vehicle market – specifically, maritime vessels and large trucks:

• Proposed site could be ideal for peak-shaving on the PSE distribution system

• Cost savings might be achieved through a larger, combined-use project

• Project could also provide reliable local supply for Gig Harbor and a future satellite to serve PSE’s Kittitas system

28

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

$4.5020

11

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

$2010

Fuel Cost Per Gallon Equivalent (Source: EIA 2012 AEO)

Gasoline Diesel Natural Gas

29

LNG Peak-ShavingTo be considered in IRP for gas customer portfolio:

• 30,000 Dth per day vaporization• 300,000 Dth (3.6 million gallons LNG) storage

for up to 10 days of service• Size limited by ability of distribution system to

absorb the vaporized supplyCosts to PSE gas customer portfolio would include contracted use of:

• Portion of larger, combined-use storage tank• Vaporization equipment• Portion of truck-loading capacity• Portion of liquefaction capacity (250 days to

refill)

30

LNG Peak-Shaving

It may be possible to increase the peaking resource by the amount of plant inlet:

•Supply that would have been used for liquefaction is diverted to other city-gates to serve gas customers•LNG service would rely on previously stored volumes on those few days

31

LNG Peak-Shaving

Additional considerations:• Could the addition of LNG peak-shaving in the

gas portfolio displace some Jackson Prairie storage, which could then be used by the electric portfolio?• Better fit resource for type of need –

• Gas portfolio demand is very weather sensitive with a significant needle-peak, protecting against extreme cold weather conditions (13º F @ Seatac)

• Electric portfolio requires flexible injections & withdrawals for intra-day supply or sink

• Transfer price issues to be resolved

Gas Supply Assumptions for Generic Resources - Draft

32

Notes: 1.Firm Pipeline Capacity: Assume firm pipeline capacity to liquid market hub(s)2.Storage Flexibility: For the gas for power portfolio assume maintenance of current ratio of storage capacity to peak gas demand (approximately 20%).3.Storage may substitute for pipeline capacity in some cases.

Gas Supply Cost Assumptions for Generic Resources - Draft

33

Westside CCCT & Peakers w/o Oil Back-up - 100% Sumas on NWP + 50% Station 2 on Westcoast

Fixed Demand ($/Dth/day)

Variable Commodity

($/Dth)ACA Charge

($/Dth) Fuel Use (%)

Utility Taxes (3.852% - if

located in WA)NWP Expansion (1) 0.500 0.030 0.0018 1.90%Westcoast @ 50% 0.210 0.010 1.60%Storage (@ 20% of Demand) (2) 0.037 0.000 2.00%

Total 0.747 0.040 0.0018 5.50% 3.852%

Annual Fixed Cost for 50,000 Dth/day Plant ($/yr) = $13,631,500

Eastside CCCT & Peakers w/o Oil Backup - 100% AECO on GTN/Nova/Foothills

Fixed Demand ($/Dth/day)

Variable Commodity

($/Dth)ACA Charge

($/Dth) Fuel Use (%)

Utility Taxes (3.852% - if

located in WA)NOVA (TC-AB) 0.170 0.00 0%Foothills (TC-BC) 0.097 0.00 1.10%GTN to Stanfield 0.177 0.004 0.0018 1.39%Storage (@ 20% of Demand) (2) 0.037 0.000 2.00%

Total 0.481 0.004 0.0018 4.49% (3)

Annual Fixed Cost for 50,000 Dth/day Plant ($/yr) = $8,783,319

Notes:(1) Estimated NWP Sumas to PSE Expansion

(3) Assume Eastside plants located in Oregon near Stanfield.(4) Pipeline demand costs are assumed to escalate at 1.25% per year.

(2) Storage requirements are based on current storage withdrawal capacity to peak plant demand for the gas for power portfolio (approx. 20%).

Lunch Break & Electric Acquisition Update

34

Colstrip Discussion

Colstrip Ownership Structure

Approach in IRP

Colstrip Transmission

Case Studies

Q & A

Next Steps

36

Colstrip Ownership Structure

Approach

Key Finding From Analysis Presented on Sept 6:

Colstrip Won’t Have Significant Impact on Mid-C Price Forecast

Allows More Flexibility in Market Portfolio Analysis

Additional Assumptions—Colstrip Compliance Cases

Three Compliance Cases

Units 1&2 and Units 3&4 Analyzed Independently

Include Opportunity Cost of Transmission

Colstrip Portfolio Analysis

Remove Units 1 & 2 and Units 3 & 4 from Portfolio in 2014

Questions: Would Units 1 & 2 and Units 3 &4 Be Economic Under Each Case? Different Market Scenarios Change Answer? Benefits/Costs Relative to Societal Costs?

Colstrip Case Studies

Refer to Hand Out

Colstrip Units 1 & 2 Case Studies

Colstrip Unitis 3 & 4 Case Studies

38

39

Colstrip

Townsend

GarrisonPSE

Colstrip Transmission

Three Primary Segments of Transmission

Colstrip to Townsend: Joint Owners

Townsend to Garrison: BPA (~Joint Owners Contract 2027)

Garrison to PSE: BPA Transmission (5-Year Terms)

Opportunity Cost of Transmission

What Transmission Cost Would Be Avoided if Colstrip Was Not In Portfolio?

Garrison to PSE: ~$13.5 Million/Year

Townsend to Garrison: ~$5 Million/Year After 2027

Colstrip to Townsend: Sunk

40

Additional Discussion

Remediation Costs

Other Regulatory Impacts

Processes

41

Demand-Side Resources: Electric & Gas

Gas Utility Resource Needs

Gas Resource Alternatives

Colstrip

42

Wrap Up for Today

43

Anticipated 2013 IRP Work Plan Schedule for Public Participation-October 15, 2012

Feb Mar Apr May June July Aug Sept Oct Nov Dec Jan Feb Mar Apr MayFrame & ScenariosResource NeedsDefine AlternativesAnalysis of AlternativesAnalysis of Results Conclusions & DraftingFinalization & Production

2012 2013

Thurs, Sept 6in Bellevue at

PSE in Summit Room

Work Plan

Draft IRP

Final IRP

Nov 14+15in Bellevue

at PSE in Forum Room

Tues, Jan 22in Bellevueat PSE in

Forum Room

Tues, Mar 5in Bellevueat PSE in

Forum Room

Tues, Apr 23in Bellevueat PSE in

Forum Room

Tues , May 1in Bellevueat PSE in

Forum Room

Tues, March 6in Bellevue at PSE in Forum

Room

Tues , June 21in Bellevueat PSE in

Summit Room

Thank You!

44