2015 IRP Advisory Group - Puget Sound Energy · PDF file2 Agenda September 25, 2014 IRPAG Time Topic Presenter 9:00 – 9:15 Introduction/Review Action Items Lyn Wiltse (facilitator)

2015 IRP Advisory Group

September 25, 2014 IRPAG

2

Agenda


Time Topic Presenter

9:00 – 9:15 Introduction/Review Action Items Lyn Wiltse (facilitator)9:15 – 10:00 IRP Process Phillip Popoff10:00 – 10:30 Energy Storage Patrick Leslie10:30 – 10:45 Break -

10:45 – 11:45 2015 IRP Electric Resource Alternatives Elizabeth Hossner

11:45 – 12:15 Lunch -12:15 – 1:00 Gas Resources Supply Alternatives Bill Donahue1:00 – 1:30 EPA Clean Power Plan: 111 (d) Phillip Popoff1:30 – 1:45 Regional Market Shortfall Phillip Popoff1:45 – 2:45 Scenarios Elizabeth Hossner2:45 – 3:00 Wrap Up/Review Action Items Lyn Wiltse (facilitator)

Introductions &Review Previous Action Items


4

Agenda






IRP ProcessPhillip PopoffManager, Integrated Resource Planning


6

Purpose of IRP Analysis


Purpose1. Least Cost

Resource Mix

2. Understand Cost Risk

Purpose1. Least Cost

Resource Mix

2. Understand Cost Risk

Conclusions1. How uncertainty in key

assumptions affects least cost portfolio

2. How different resources affect portfolio cost and cost risk (TailVar90)

3. How different resource additions support reliability operations

Conclusions1. How uncertainty in key

assumptions affects least cost portfolio

2. How different resources affect portfolio cost and cost risk (TailVar90)

3. How different resource additions support reliability operations

…

7

IRP Process


Resource Needs

Planning Assumptions &

Resource Alternatives

Analysis of Alternatives

Portfolio Analysis

Analysis of Results

Decisions

Commitment to “Action”

You are Here

LOLP

8

Planning Assumptions


Wholesale Market Price

Forecasts




Portfolio Analysis

How will different resource alternatives

dispatch to market and perform in our

portfolio?

All other assumptions

9September 25, 2014 IRPAG

PNW MTEast

IDSouth

WY

CO

NMAZ

UT

NVSouth

NVNorthCA

North

CA South

BC AB

Aurora System Diagram for

WECC

The System Diagram provides an object view of

each Zone Definition system being modeled. A System Diagram has been

created for all delivered Zone Definition Systems.

Baja No

Legend – Transmission Links:< 650 MW650 – 2000 MW> 2000 MW

10





portfolio?

Resources Dispatched to Market

Existing Resources

New Resources

Resources Perform in

PSE’s portfolio

Capacity Needs

Energy Needs

REC Needs

Flex Needs

11

Models/Tools


Wholesale Market Price

Forecasts




Portfolio Analysis



portfolio?

All other assumptions

Aurora

“PSM III”

AuroraFinancial

Risk Solver

Platform

Flex

StochasticModeling

12

Agenda






Energy StoragePatrick LeslieEmerging Technology Program Manager



Storage projects are scaling-up

AES Laurel MountainPower: +32/-32 MWEnergy: 7.5 MWhCOD: 2011 Q4Location: W. VirginiaUse: Frequency

regulation

Duke NotreesPower: +36/-36 MWEnergy: 24 MWhCOD: 2012 Q4Location: TexasUse: Frequency

regulation

(for certain applications)


Storage projects are scaling-up

AES Tait StationPower: +20/-20 MWEnergy: 10 MWhCOD: 2013Location: OhioUse: Frequency

regulation

Golden Valley ElectricPower: +40/-40 MWEnergy: 10 MWhCOD: 2003Location: OhioUse: Spinning reserve

load following,AGCVAR support,

(for certain applications)


Storage projects are proliferating

Utility ProjectCapacity

(MW) Location Technology Project StartPGE Salem 5.0 Oregon Li-ion 2013Energy Northwest Nine Canyon 0.1 Washington Li-ion 2013

SnoPUD MESA 1.0 Washington Li-ion 2013

BC Hydro Golden 1.0 British Columbia Sodium sulfur 2011

PG&E Various 6.0 California Sodium sulfur 2013

SCE Tehachapi 8.0 California Li-ion 2012

SDG&E San Diego 1.5 California Li-ion 2013

SMUD Sacramento 1.0 California Zinc bromine 2012

Duke Notrees 36.0 Texas Adv. lead acid 2012

AES Laurel Mountain 32.0 Virginia Li-ion 2011

Dayton Power & Light Tait Station 30.0 Ohio Li-ion 2013

Golden Valley Electric GEVA 46.0 Alaska Sodium nickel 2003

[partial list]


Behind-the-meter storage is emerging

10 MW+ deployed; 500+ interconnection requests in CA.

15 MW+ development pipeline

Storage systems shave peaks, reduce demand charges, shave TOU rate blocks, and may provide backup power. Installed under lease or PPA terms.


PSE’s Battery Energy Storage ProjectsPRIMUS POWER GLACIER

Size 0.5 MW / 1.0 MWh 2.0 MW / 4.4 MWh

Tech Zinc-Bromine Flow Battery Lithium-Ion Battery

Location TBA Glacier, WA (remote community)

Est. COD Q2 2015 Q4 2015

Purpose Substation peak shaving, peaking capacity, ancillary services, outage mitigation

Outage mitigation, peaking capacity, ancillary services.

Partners BPA, Primus Power, PNNL, U.S. Dept. of Energy

WA Dept. of Commerce, RES Americas, 1Energy Systems, PNNL, U.S. Dept. of Energy


Primus Power Project

Phase 1 Report

20

Results Summary – Bainbridge Island(NPV benefits and revenue requirements over 20-year time horizon)

21

Random Outages – Mid‐C Capacity

Value

Projected Outages – Mid‐C Capacity

Value


What’s inside an EnergyPod®?

EnergyPod w/14 EnergyCells

PowerBox (Power Conversion System)

Transformer

Thermal Mgmt. System


Primus Power – Draft Layout (0.5MW / 1.0MWh)


Glacier Project

1) Battery System• Size 2.0MW / 4.4MWh• Technology: BYD Lithium-ion• Site: Glacier, WA• Est. COD: Q3 2015

Primary Goals:• Enhance service reliability (outage mitigation)• Demonstrate provision of peaking capacity and balancing resources/ancillary

services.• Automatically dispatch the system using advanced software and IT

2) Support MESA (Modular Energy Storage Architecture) Standards• Utilize MESA standards to connect ESS to SCADA, EMS, & other grid control

systems • Advance and publish MESA interfaces via standards organizations:

• IEEE 2030.2 Energy Storage Working Group• IEC TC-120 Electric Energy Storage technical committee

Seattle Bellevue

Tacoma

Buckley

Similar 4MW/2MWh BYD system; Ontario, Canada


Glacier ProjectIssue: Frequent transmission-line outages due to vegetation.

Solution: Locate ESS near Glacier substation to provide backup power to GLA-12.

Phase 1: Use storage system to provide backup power to the “downtown” area for businesses.

Phase 2:Attempt to develop a full microgrid with the storage system and Nooksack Hydro (highly complex).


Glacier Draft Layout (2.0MW / 4.4MWh)


Similar Projects


Large-Scale Storage Generic Costs

Units Lithium Ion Battery

Flow Battery (VRB) Pumped Hydro

Power MW 20

Energy MWh 80

Discharge at Nameplate Power Hours 4.0

Recharge at Nameplate Power Hours 4.5

R/T Efficiency % 87%

Station Footprint Acres 0.75

Capital Cost ($/kW) $3,000

Fixed O&M ($/kW-yr) $20

Variable O&M $/MWh $0

Forced Outage Rate % 0.5%

Capacity Credit % 100%

Operating Reserves % Tbd

Book Life Years 20

Work in Progress


Primary Values of Storage

• T&D upgrade deferral involves delaying – and in some cases avoiding entirely –investments in T&D upgrades by using relatively small amounts of storage.

• In some cases, installing a small amount of storage downstream from the nearly overloaded node could defer the major upgrade for several years.

T&D Upgrade Deferral

• “Flexibility” refers generally to two services:• 1) ESS to provides balancing reserves -- capacity

held back on the PSE system to respond to negative and positive frequency errors, and for load and generation following.

• 2) Operating reserves -- capacity that can be called upon when some portion of the normal electric supply resources become unavailable unexpectedly

System Flexibility

• ESS is dispatched during system peaks and may defer and/or to reduce the need to buy new central station generation capacity and/or purchasing capacity in the wholesale electricity marketplace.

Capacity


Analysis Framework

1

• Work with T&D planners to identify 1-2 sites where grid storage might alleviate constraints and/or improve reliability.

• Identify ESS size and performance specifications required for application.

• Determine years of project deferral and associated savings.

2• Use PSE’s “flexibility model”, an AURORA and mixed integer linear

program (MILP) model, to determine the value of balancing reserves provide by ESS.

3

• Subtract NPV of T&D deferral and balancing value from capital cost of battery system.

• Model as generic resource into typical IRP resource optimization.

31

Break


32

Agenda






2015 IRP Electric Resource AlternativesElizabeth HossnerSenior Analyst, Integrated Resource Planning


34

Agenda


• Thermal Resources• CCCT • Peakers

• Frame• Hybrid Aero Derivative• Reciprocating Internal

Combustion Engine (RICE)• Renewable Resources

• Wind• Solar• Biomass

35

Thermal Resource Assumptions


• All thermal resource assumptions from Black & Veatch (B&V) report commissioned by PSE

• General assumptions:• Assume 40% Owner’s cost for outside-the-fence, project

development, project financing, and escalation• Heat rates include a 2% increase for degradation• CCCT in compliance with Washington Emission Performance

Standards (EPS) – 970 lbs/MWh• Capital costs include selective catalytic reducer (SCR)• CCCT – 1x1 wet cooled

• Dry cooled 5% capital cost increase• O&M cost impact negligible (add costs for air cooled

condenser, but save costs for water supply and water treatment)

36

Thermal Resources


CCCT

GE 7FA.05

1 on 1 configuration w

DF

335 MW Winter Capacity + 50

MW DF

$1,396/kW + $325/kW DF

Frame CT

GE 7FA.05

1x 226 MW Configuration

228 MW Winter Peak

$837/kW

Aero CT

GE LMS 100 PA


206 MW Winter Capacity

$1,255/kW

Reciprocating Engine

Wartsila 18V50SG


220 MW Winter Capacity

$1,600/kW

37

Oil Back-Up for Peakers


• Oil back-up for Heavy Frame and Aero Peakers• Difficult to get air permits for Recip Engines• $15 Million one time cost added to EPC• 2015 IRP cost estimate includes fuel oil storage tank, initial

inventory, demineralized water production and storage system and additional balance of plant facilities such as roads, electrical supply and distribution, foundations, excavation, diesel truck unloading pads and pumps, truck hookups, etc.

Frame CT Aero CTTotal Incremental cost (added to capital cost) $66/kW $68/kW

FOM (added to FOM for plant) $8.92/kW-yr $8.92/kW-yrPrice of Oil $3.00/Gal $3.00/GalDays of Oil 2 days 2 days

38

Renewable Resource Assumptions


• RES• Next build of Lower Snake River (LSR)Wind

• Utility Scale• E3 Generation Capital Cost Report for WECC • Central to Southern Washington• Fixed Tilt PV

Solar

• EIA Capital Cost Report -http://www.eia.gov/forecasts/capitalcost/

• Located in Western Washington• Biomass Bubbling Fluidized Bed (BBFB)

Biomass

39

Renewable Assumptions


2014 $ WA Wind MT Wind Solar BiomassCapacity (MW) 100 100 20 15All in Cost ($/KW) 2,048 2,048 3,742 4,455Fixed O&M ($/KW-yr) 27.12 27.12 27.00 105.63Variable O&M ($/MWh) 3.15 3.15 5.26Capacity Factor 34% 41% 20% 88%Capacity Credit 8% 0% 100%/0%Location SW WA Central MT Central WA West WAFixed Transmission ($/kW-yr) 35.23 52.68* 23.35 20.83Variable Transmission ($/MWh) 1.83 1.83 1.83 0.33

*$35.23/kW-yr (PSE to Garrison) + $17.45/kW-yr (Garrison to Colstrip)

40

Generic WA Wind Monthly Capacity Factor


0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

35.0%

40.0%

45.0%

50.0%

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Monthly CF

Annual CF

41

Wind vs. Solar Monthly Shapes


0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

35.0%

40.0%

45.0%

50.0%


Cap

acity

Fac

tor

WA Wind

Solar

42

Wind vs. Solar Cost Curve


0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035

Real 2014 $/kW

Capital Cost ComparisonReal 2014 $/kW

PSE (E3) Solar PV Estimate (20 MW)

EIA ‐ 2013 AEO Solar PV (20 MW)

2013 IRP Wind w AEO curve

New Project Costs and Estimates from SNL Energy

Final data point from SNL Energy

Estimated using AEO cost Curve

43

Montana Wind


Colstrip

Garrison

44

Montana Monthly Wind Shapes


0%

10%

20%

30%

40%

50%

60%

70%


WA Wind ‐ 34% Annual Capacity Factor

MT Wind ‐ 41% Annual Capacity Factor

45

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Capa

city Factor

Hours

Hourly Data for Dec. 19, 2007 (Thurs)

Judith Gap

Hopkins Ridge


46

Next Steps for Electric IRP


• Scenarios• Power Prices

• Draft prices and assumptions review in October• Final prices in December

• Draft Portfolio results in March


Lunch

48

Agenda






Gas Resource Supply AlternativesBill DonahueManager, Natural Gas Resource


50

Gas Resource – Options


51

Gas Resource - Options


• Option #1 – Purchase BC gas at Station 2 and transport via existing or expanded capacity on Westcoast, along with an expansion of Northwest Pipeline (NWP).

• Option #2 – Purchase AECO gas and transport via existing or expanded capacity on NGTL and Foothills pipelines, along with the proposed Fortis BC Kingsvale -Oliver Reinforcement Project (KORP) and a NWP expansion.

• Option #3 – Purchase AECO gas and transport via existing or expanded capacity on NGTL, Foothills, GTN, along with a new Cross-Cascades pipeline with a NWP expansion. (N-MAX, Palomar/Blue Bridge).

• Option #4 – Purchase gas at Malin, transport by back-haul on GTN and transport on a new Cross-Cascades pipeline with a NWP expansion.

• Option #5 – Develop an on-system LNG peaking resource in combination with a plant serving transportation market.

• Option #6 – Develop a stand-alone on-system LNG peaking resource• Option #7 – Upgrade the existing Swarr LP-air facility and return to service.

52

Tacoma LNG


• Proposed LNG plant to serve gas system peaking needs, combined with serving transportation market.

• Facilities would include: liquefaction, storage, vaporization and ship/barge/truck-loading.

• Gas system peaking resource: 85,000 Dth per day for up to 6 days equivalent per year • vaporization of 66,000 Dth/d directly into Tacoma area gas system • diversion of 19,000 Dth/d of flowing gas (which would otherwise be

liquefied) to other portions of the PSE gas system

• Expected available during winter 2018-19.

• Upgrade of PSE gas system will be required and the cost will be considered in the analysis.

• Initial analysis indicates Least Cost, but will be examined in 2015 IRP.

53

New Resource


• PSE has executed a letter of intent to obtain the long-term use of a gas resource in the region.

• 50,000 Dth/day each for both the gas book and the power book.• Term: April, 2016 – March, 2046• 1/2 recallable after 20 years• some regulatory authorizations are necessary, but expected to be

approved• availability of this resource was not anticipated in the last IRP, but detailed

analysis determined it to be least-cost relative to those that were studied• this resource postpones gas portfolio need for 3-4 years.• this resource replaces an expiring resource in the power portfolio.• the resource will be considered part of the existing portfolios for purposes

of the new IRP.• more details will be shared after discussions with regulators.


Puget Sound Energy 2015 IRP (2016-2035) - Draft 09/25/14Prospective Pipeline Alternatives

Current Rates

Maximum Capacity

Available In Sendout

Capacity Demand

Variable Commodity Fuel Use

Alternative From/To Years Available (MDth) ($/Dth/day) ($/Dth) (%) Comments

Vintage NWPRockies, Sumas, GTN to PSE City

Gate‐

existing contracts

0.41 0.03 1.4No additional vintage NWP capacity is available from

NWP (Some may be available in market)

Expansion of NWPSumas to PSE City Gate

Oct. 2018, 2020,2024, 2028

& 2032200 0.50 0.03 1.9 Prospective project, estimated costs

Westcoast Capacity (T‐South)

Station 2 to Sumas

Oct. 2016, 2018, 2020, 2024, 2028

& 2032200 0.40 0.01 1.6

Uncontracted firm capacity is available. Downstream required: NWP

Fortis BC KORP Expansion

Foothills to Sumas (Bi‐directional)

Oct. 2017, 2018, 2022,2026 &

203050 0.60 0 0

Prospective project, estimated costs. Upstream required: NGTL, Foothills. Downstream required: NWP

NGTL PipelineAECO to

Alberta/BC border

Oct. 2016, 2018, 2020, 2024, 2028

& 2032100 0.17 0 0

Uncontracted firm capacity is available. Downstream required: Foothills plus: GTN and NWP or Fortis KORP

and NWP or GTN and Cross Cascades and NWP

Foothills PipelineBC Border to Kingsgate

Oct. 2016, 2018, 2020, 2024, 2028

& 2032100 0.097 0 1.1

Uncontracted firm capacity is available. Upstream required: NGTL. Downstream required: GTN and NWP or Fortis KORP and NWP or GTN and Cross Cascades

and NWP

GTN PipelineKingsgate to Stanfield

Oct. 2016, 2018, 2020, 2024, 2028

& 2032100 0.177 0.004 1.4

Uncontracted firm capacity is available. Upstream requird: Foothills and NGTL Downstream required:

NWP

Cross Cascades (N‐MAX,

Palomar/Blue Bridge)

Stanfield to PSE City Gate

Oct. 2018, 2020,2024, 2028

& 2032200 0.80 0.005 2.0

Prospective project, estimated costs. Upstrean required: GTN, Foothills and NGTL or GTN Backhaul.

Downstream required: NWP

GTN "Backhaul"Malin to Stanfield

Oct. 2016, 2018, 2020, 2024, 2028

& 2032100 0.21 0.0054 0

Uncontracted firm capacity is available. Downstream required: NWP or Cross Cascades and NWP

55

Discussion Topic - upstream Westcoast pipeline capacity


• Current PSE strategy is to hold Westcoast T-South firm pipeline capacity approximately equal to 50% of our firm requirements at Sumas.• Strategy applicable to both Gas Book and Power Book• Purpose is two-fold:

• physical reliability (more guaranteed access to actual gas supply near the source)

• pricing diversity (Station 2 vs Sumas price)

• Firm requirements at Sumas defined as: Sumas firm receipt capacity on Northwest Pipeline firm transportation agreements plus any firm generation requirements not connected to NWP in Whatcom County

Current status of strategy:

Gas Book Power BookTotal NWP firm capacity 523,053 167,885 non-Sumas receipts 261,552 78,928 Sumas Receipts 261,501 88,957 Sumas CCCT 26,000 Ferndale CCCT 58,900 Total Sumas requirements 261,501 173,857

PSE policy- 50% 130,751 86,929

Westcoast T-south contracts 129,855 84,487

Sumas reqmts without T-South 131,646 89,370 Total

Dth/d at Nov. 1, 2014

221,016


From a recent Westcoast presentation


From a recent Westcoast presentation

58

Westcoast is fully utilized in high demand periods, and demand is expected to grow………


• Significant new high load-factor demands on the horizon (2017/18) could easily tighten available supplies and force expansion

• Expansion could take 4 years to complete• Expansion would result in higher rates for all

(rolled-in rates)• Westcoast preparing to offer a Deferred

Reservation Option Open Season before year-end 2014

• Parties could reserve capacity to start up to 4 years out, but must make minimum 10 year commitment when contract starts

• Cost of Deferred Res. Option = $7.30 /Dth/Yr, after first 12 months

Gas Book Power BookSumas reqmts without T-South 131,646 89,370

Total

Cost of Def'd Reservation/Yr 961,016$ 652,401$ Total

221,016

$ 1,613,417

• musical chairs effect: bystander could be left without access to gas at Sumas until expansion is completed

• PSE may consider signing up for Deferred Reservation Option for its “Sumas Requirements without T-South” of 221,000 Dth/d at a cost of $1.6 M per year.

Min. Max.Woodfibre LNG 200 250 Fortis BC‐ Local LNG 50 60 Fortis BC ‐Hawaii LNG 100 120 Other Non‐Methanol 225 275 Total 575 705

Winter Design Capacity 1,702 1,702 existing contracts, extended 1,100 1,000 available for new contracts 602 702

Summer Design Capacity 1,530 1,530 existing contracts, extended 1,100 1,000 available for new contracts 430 530

Expected new high load-factor load (MDth/d)

59

Questions / Discussion


Thank You

60

Agenda






EPA Clean Power Plan: 111 (d)Phillip PopoffManager, Integrated Resource Planning


62

Presentation Outline

• 111 (d) Overview

• Initial Observations

• Ideas for Recommendations

• Initial Forecast of WA Compliance


63

Overview

EPA Using Clean Air Act to Regulate GHG Emissions from Power Plants

Final Goal: 30% reduction in National CO2 emissions by 2030 Relative to 2005 levels (?)

Interim Targets Staring 2020

New Sources Under CCA “111 (b)”

Standards Less Stringent than WA?

Existing Sources under CCA “111 (d)”


64

Approach

State-Level Goals: Solo or Coordinate• Emission Targets Proposed for Each State• Flexibility: States Can Cooperate on Regional Approaches

to Meet Combined Targets

Form of Targets: 2 Choices• Emission Rates: lbs/MWh--

• Flexibility: States Can Switch to Mass (tons) Limit

“Adjusted” Thermal Plant Emissions in lbsSum (Thermal, New Renewable, New DSM, @Risk Nuke) in MWh


65

Best System of Emission Reduction

• EPA’s State Specific Goals Based on “BSER”

• Best System of Emission Reduction

• New (Maybe Questionable) Regulatory Concept

• EPA Interpreted BSER Broadly

• Includes direct emissions reductions and “beyond unit” or “beyond fence-line” measures such as re-dispatch, demand-side energy efficiency, renewable energy additions, and other measures that displace fossil sources of generation.


66

Methodology for Goals

EPA is proposing that BSER is based on four “building blocks” for reducing emission rates:

1. Improved average heat rates at coal-fired EGUs on average by 6%2. Re-dispatch from coal-based to natural gas-based units (based on an

assumed 70% utilization rate) 3. Expanded renewable electric generating capacity + @ risk nuclear4. Expanded use of demand-side energy efficiency

(READ THE FINE PRINT…SHOWN IN THEIR MATH!)

Alternative: Just Includes First Two building blocks.

• EPA is asking for comment on this more limited and legally defensible definition of BSER


67

Best System of Emission Reduction

• EPA’s State Specific Goals Based on “BSER”

• Best System of Emission Reduction

• New (Maybe Questionable) Regulatory Concept

• EPA Interpreted BSER Broadly

• Includes direct emissions reductions and “beyond unit” or “beyond fence-line” measures such as re-dispatch, demand-side energy efficiency, renewable energy additions, and other measures that displace fossil sources of generation.


68

111 (d)--Plants Affected in WA

Coal and Gas-Fired CCCT

PSE Plants• Encogen, Ferndale, Fredrickson, Goldendale, Mint Farm,

Sumas

The Rest• Chehalis, Grays Harbor, March Point, River Road• Centralia Coal Plant


69

Initial Observation

• Inadequate Consideration of How Rule Will Affect Reliability at State/Regional Level

• Minimal Consideration of Costs to Customers

• Overly Complex & Over-Reaching Approach Will Delay Emission Reductions


70

Specific Concerns

• WA Interim Goal Seems Unattainable (2022-2030)

• BSER Definition Usurps State Authority

• No Recognition for WA’s Early & Innovative Leadership

• 2012 Baseline Year Not Representative of Regional Variability

• 2030 Emission Goal: WA Appears Close But…

• Inconsistent with Market—Cannot Demonstrate a Link Between Building Blocks and Dispatch of In-State Resources


71

111 (d)—Key Recommendations• Simplify: Set Mass Targets by State for Affected Existing

Resources and Allow States to Develop Multistate Approaches

• Provide Flexibility on Interim Goals

• Provide Flexibility to Address Hydro Variability

• Verify Washington’s Early Leadership Actions Count

• Provide the CO2 Mass Targets by Year for Each State

• Provide Flexibility on Defining Energy Efficiency


72Page 726/14/2014

5 yr avg CO2 12.3 mil tons

73


-

2,000,000

4,000,000

6,000,000

8,000,000

10,000,000

12,000,000

14,000,000

2020 2021 2022 2023 2024 2025 2026 2027 2028 2029

Car

bon

Dio

xide

Em

issi

ons

(tons

)DRAFT - WA Estimated CO2 Cap and Performance

in Tons

PSE Estimated-WA

EPA Target Emissions-WA

5 Year Average (2008-2012)Emissions from EGUs

Over 10-Year Period, WA Projected to be Short 14.9 Million TonsLonger-Term WA Projected to Be Below Target

65% Reduction

75

Next Steps

• Comments to EPA: October 2014 Dec 1, 2014

• Final Rule: June 2015

• State Implementation Plans in 2016 or 2017


76

Agenda






Regional Market FallPhillip PopoffManager, Integrated Resource Planning


78

Short Capacity in a Short Market!1 *Market Short from NWPCC Analysis by 2021: (2,000) MW2 Adjustment‐‐Resources Missed by Council: 69 MW3 Additional Short‐Big Hanaford: (322) MW4 Net Resource Surplus/(Shortfall): (2,253) MW

Resources Under Construction5 PacifiCorp‐‐Lakeside 2: 645 MW6 Portland General‐Carty: 440 MW7 Portland General‐Port Westward 2: 220 MW8 Total Under Construction: 1,305 MW

9 Net Market Shortfall: (948) MW

10 PSE's 2021 Reliance on Short‐Term Market for Capacity: 1,662 MW11 **PNUCC‐Total Utility Market Reliance at Peak: 5,141 MW

*‐‐See 2013 IRP Appendix I, p. 7 for January 8, 2013, NWPCC memo.**‐‐Information from PNUCC's 2014 Northwest Regional Forecast (NRF)


79

Agenda






Scenarios Elizabeth HossnerSenior Analyst, Integrated Resource Planning



Scenarios

Low

Mid

High

Low Gas

No CO2

Low Load

Mid Gas

MidCO2

Mid Load

High Gas

High CO2

High Load

Fully Integrated Scenarios


Scenarios

GasCO2

Load

Mid Gas

Mid CO2

Mid Load

GasCO2

Load

Low Gas

High Gas

No CO2

High CO2

Low Load

High Load One-Off

Scenarios

Fully Integrated Scenarios


Scenarios

Colstrip

GasCO2

Load Mid Gas Mid LoadGas

CO2Load

Low Gas

High Gas

No CO2

High CO2

Low Load

High Load

All 4 Units in Service

Retire Units 1 & 2

Retire all 4 Units

Low High

Mid CO2

Mid

Portfolio Sensitivity

84

CO2 Price

September 25, 2014 IRPAG0

20

40

60

80

100

120

140

2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035

Nominal $/ton

2015 IRP Low ‐ No CO2 Price

2015 IRP Mid Option 1‐ Wood Mackenzie Spring 2014

2015 IRP Mid Option 2 ‐ NWPCC CA

2015 IRP High ‐ Wood Mackenzie High


86

Regional Load Forecast

September 25, 2014 IRPAG 15,000

16,000

17,000

18,000

19,000

20,000

21,000

22,000

23,000

24,000

25,000

2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035

Pacific Northwest Annual Demand (aMW)WA, OR, ID, MT‐West

2015 IRP Mid ‐ NPCC 2013 Forecast

6th Power Plan Less Cons. (Feb 2010)

87

Agenda






Wrap Up & Review Action Items




Thank You

2015 IRP Advisory Group - Puget Sound Energy · PDF file2 Agenda September 25, 2014 IRPAG Time Topic Presenter 9:00 – 9:15 Introduction/Review Action Items Lyn Wiltse (facilitator)

Documents