2015 IRP Advisory Group - Puget Sound Energy · PDF file2 Agenda September 25, 2014 IRPAG Time...
Transcript of 2015 IRP Advisory Group - Puget Sound Energy · PDF file2 Agenda September 25, 2014 IRPAG Time...
2015 IRP Advisory Group
September 25, 2014 IRPAG
2
Agenda
September 25, 2014 IRPAG
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
September 25, 2014 IRPAG
4
Agenda
September 25, 2014 IRPAG
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)
IRP ProcessPhillip PopoffManager, Integrated Resource Planning
September 25, 2014 IRPAG
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Purpose of IRP Analysis
September 25, 2014 IRPAG
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
September 25, 2014 IRPAG
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
September 25, 2014 IRPAG
Wholesale Market Price
Forecasts
Planning Assumptions &
Resource Alternatives
Analysis of Alternatives
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
Analysis of Alternatives
September 25, 2014 IRPAG
How will different resource alternatives
dispatch to market and perform in our
portfolio?
Resources Dispatched to Market
Existing Resources
New Resources
Resources Perform in
PSE’s portfolio
Capacity Needs
Energy Needs
REC Needs
Flex Needs
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Models/Tools
September 25, 2014 IRPAG
Wholesale Market Price
Forecasts
Planning Assumptions &
Resource Alternatives
Analysis of Alternatives
Portfolio Analysis
How will different resource alternatives
dispatch to market and perform in our
portfolio?
All other assumptions
Aurora
“PSM III”
AuroraFinancial
Risk Solver
Platform
Flex
StochasticModeling
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Agenda
September 25, 2014 IRPAG
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)
Energy StoragePatrick LeslieEmerging Technology Program Manager
September 25, 2014 IRPAG
14September 25, 2014 IRPAG
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)
15September 25, 2014 IRPAG
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)
16September 25, 2014 IRPAG
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]
17September 25, 2014 IRPAG
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.
18September 25, 2014 IRPAG
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
19September 25, 2014 IRPAG
Primus Power Project
Phase 1 Report
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Results Summary – Bainbridge Island(NPV benefits and revenue requirements over 20-year time horizon)
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Random Outages – Mid‐C Capacity
Value
Projected Outages – Mid‐C Capacity
Value
22September 25, 2014 IRPAG
What’s inside an EnergyPod®?
EnergyPod w/14 EnergyCells
PowerBox (Power Conversion System)
Transformer
Thermal Mgmt. System
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Primus Power – Draft Layout (0.5MW / 1.0MWh)
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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
25September 25, 2014 IRPAG
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).
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Glacier Draft Layout (2.0MW / 4.4MWh)
27September 25, 2014 IRPAG
Similar Projects
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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
29September 25, 2014 IRPAG
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
30September 25, 2014 IRPAG
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.
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Break
September 25, 2014 IRPAG
32
Agenda
September 25, 2014 IRPAG
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)
2015 IRP Electric Resource AlternativesElizabeth HossnerSenior Analyst, Integrated Resource Planning
September 25, 2014 IRPAG
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Agenda
September 25, 2014 IRPAG
• Thermal Resources• CCCT • Peakers
• Frame• Hybrid Aero Derivative• Reciprocating Internal
Combustion Engine (RICE)• Renewable Resources
• Wind• Solar• Biomass
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Thermal Resource Assumptions
September 25, 2014 IRPAG
• 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)
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Thermal Resources
September 25, 2014 IRPAG
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
2x 103 MW Configuration
206 MW Winter Capacity
$1,255/kW
Reciprocating Engine
Wartsila 18V50SG
12x 18 MW Configuration
220 MW Winter Capacity
$1,600/kW
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Oil Back-Up for Peakers
September 25, 2014 IRPAG
• 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
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Renewable Resource Assumptions
September 25, 2014 IRPAG
• 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
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Renewable Assumptions
September 25, 2014 IRPAG
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)
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Generic WA Wind Monthly Capacity Factor
September 25, 2014 IRPAG
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
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Wind vs. Solar Monthly Shapes
September 25, 2014 IRPAG
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
Cap
acity
Fac
tor
WA Wind
Solar
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Wind vs. Solar Cost Curve
September 25, 2014 IRPAG
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
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Montana Wind
September 25, 2014 IRPAG
Colstrip
Garrison
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Montana Monthly Wind Shapes
September 25, 2014 IRPAG
0%
10%
20%
30%
40%
50%
60%
70%
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
WA Wind ‐ 34% Annual Capacity Factor
MT Wind ‐ 41% Annual Capacity Factor
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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
September 25, 2014 IRPAG
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Next Steps for Electric IRP
September 25, 2014 IRPAG
• Scenarios• Power Prices
• Draft prices and assumptions review in October• Final prices in December
• Draft Portfolio results in March
47September 25, 2014 IRPAG
Lunch
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Agenda
September 25, 2014 IRPAG
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)
Gas Resource Supply AlternativesBill DonahueManager, Natural Gas Resource
September 25, 2014 IRPAG
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Gas Resource – Options
September 25, 2014 IRPAG
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Gas Resource - Options
September 25, 2014 IRPAG
• 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.
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Tacoma LNG
September 25, 2014 IRPAG
• 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.
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New Resource
September 25, 2014 IRPAG
• 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.
54September 25, 2014 IRPAG
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
September 25, 2014 IRPAG
• 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
56September 25, 2014 IRPAG
From a recent Westcoast presentation
57September 25, 2014 IRPAG
From a recent Westcoast presentation
58
Westcoast is fully utilized in high demand periods, and demand is expected to grow………
September 25, 2014 IRPAG
• 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
September 25, 2014 IRPAG
Thank You
60
Agenda
September 25, 2014 IRPAG
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)
EPA Clean Power Plan: 111 (d)Phillip PopoffManager, Integrated Resource Planning
September 25, 2014 IRPAG
62
Presentation Outline
• 111 (d) Overview
• Initial Observations
• Ideas for Recommendations
• Initial Forecast of WA Compliance
September 25, 2014 IRPAG
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)”
September 25, 2014 IRPAG
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
September 25, 2014 IRPAG
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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.
September 25, 2014 IRPAG
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
September 25, 2014 IRPAG
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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.
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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
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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
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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
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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
September 25, 2014 IRPAG
72Page 726/14/2014
5 yr avg CO2 12.3 mil tons
73
74September 25, 2014 IRPAG
-
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
September 25, 2014 IRPAG
76
Agenda
September 25, 2014 IRPAG
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)
Regional Market FallPhillip PopoffManager, Integrated Resource Planning
September 25, 2014 IRPAG
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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)
September 25, 2014 IRPAG
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Agenda
September 25, 2014 IRPAG
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)
Scenarios Elizabeth HossnerSenior Analyst, Integrated Resource Planning
September 25, 2014 IRPAG
81September 25, 2014 IRPAG
Scenarios
Low
Mid
High
Low Gas
No CO2
Low Load
Mid Gas
MidCO2
Mid Load
High Gas
High CO2
High Load
Fully Integrated Scenarios
82September 25, 2014 IRPAG
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
83September 25, 2014 IRPAG
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
85September 25, 2014 IRPAG
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
September 25, 2014 IRPAG
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)
Wrap Up & Review Action Items
September 25, 2014 IRPAG
89September 25, 2014 IRPAG
90September 25, 2014 IRPAG
Thank You