2019 IRP Advisory Council Meeting January 10, 2019 · 3. Determine RegUp/RegDn for solar to comply...

2019 IRP Advisory Council Meeting

January 10, 2019

Important Notice

Some of the information discussed during today’s meeting may be confidential (for business or securities law reasons) or competitive (for anti-trust law reasons). Thus, please treat as confidential and sensitive the information provided by Idaho Power during this meeting, unless and until Idaho Power itself discloses the information publicly.

If you are uncertain whether information is either confidential or competitive, or whether any particular information has been publicly disclosed, please ask. Adhering to this practice helps protect both you and Idaho Power.

IRP Advisory Council MeetingJanuary 10, 2019

• T&D Deferral Benefit• Demand Response• Energy Imbalance Market (EIM)• Reserve Requirements• Capacity Expansion Modeling Update• Updated Resource “Placemat”

RVOS – T&D Deferral Locational Value

Jared HansenT&D Engineering & Construction Leader

January 10, 2019

Traditional Investments

Traditional Investments

2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021

BudgetedHistorical Asset Investments

168 Projects

Unit Clarification

$/MWh $/kW-Year

$/kW

Unit Clarification

𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷 𝑆𝑆𝐷𝐷𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝐷𝐷𝐷𝐷𝐷𝐷 𝑁𝑁𝐷𝐷𝑁𝑁𝐷𝐷𝑁𝑁𝐷𝐷𝐷𝐷𝑁𝑁𝐷𝐷

$/kW

Solar Locational Values

Location Years Deferred

Deferral Savings

Solar Project Size (kW)

Capacity Value ($/kW)

Blackfoot 8 $79,550 964 $82.52

Siphon (Pocatello) 4 $107,789 4,472 $24.10

Wye (Boise) 3 $19,767 2,339 $8.45

Nampa 2 $66,516 1,516 $43.87

Dietrich 2 $16,965 229 $74.08

Solar and Batteries

Solar and Batteries - Assumptions

Commercial ResidentialBattery Size

(% of solar nameplate) 25% 100%

Battery Duration (hours) 4 2.7

Summer

Winter

Service TerritoryService Area

Growth Projects

Solar Deferred

Solar + Battery

Solar + Battery Locational Values

Location Solar Size (kW)

Solar + Battery Size (kW)

Solar Capacity Value

($/kW)

Solar + Battery Capacity Value

($/kW)

Blackfoot 964 723 $82.52 $110.03

Siphon (Pocatello) 4,472 3,130 $24.10 $34.43

Wye (Boise) 2,339 862 $8.45 $22.94

Nampa 1,516 1,137 $43.87 $58.49

Dietrich 229 229 $74.08 $74.08

Non-Wire Alternatives

Jared HansenT&D Engineering & Construction Leader

January 10, 2019

Moonstone

Criteria

Is there an operational solution?

Is the load shape conducive to non-wire alternatives? Is the growth rate low?

Are non-wire solutions cost-effective compared to

the traditional solution?

2018 Non-Wire Alternative Analysis

Project CountTotal 74

Failed Criteria 71In-depth Analysis 3

Potential 1

2018 Non-Wire Alternative Analysis

Location In-Service Date

Category Traditional Solution

Non-wire Alternative

Status

Weiser 2019 Substation $622k $2.2M Not Cost Effective

Hagerman 2019 Distribution $552k $5.9M Not Cost Effective

Jordan Valley 2020 Substation $757k $544k Further

Examination

Solar Locational Values

Location Years Deferred

Deferral Savings

Solar Project Size (kW)

Capacity Value ($/kW)

Blackfoot 8 $79,550 964 $82.52

Siphon (Pocatello) 4 $107,789 4,472 $24.10

Wye (Boise) 3 $19,767 2,339 $8.45

Nampa 2 $66,516 1,516 $43.87

Dietrich 2 $16,965 229 $74.08

Demand Response as a Resource

Quentin NesbittEnergy Efficiency Program Leader

January 10, 2019

Demand Response (DR)

• Voluntary • Participants receive an incentive for

turning off equipment • Designed to avoid or delay the need

to build new supply-side peaking resources

• Capacity resource• Not to save energy; load is typically

shifted

Idaho Power Demand Response Programs

• Irrigation Peak Rewards ~ 320 MW• Flex Peak ~ 35 MW• A/C Cool Credit ~ 35 MW

History of Demand Response at Idaho Power

$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

0

50

100

150

200

250

300

350

400

450

500

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018p

Dem

and

Resp

onse

Exp

ense

s (M

illio

ns)

Peak

Dem

and

Redu

ctio

n Ca

paci

ty (M

W)

Available capacity

Actual Load Reduction

Demand responseexpenses

0%

2%

4%

6%

8%

10%

12%

14%

16%

18%

Demand Response as % of System Peak

Other Utilities

Demand Response

Reso

urce

Opt

ions

Capacity Cost

Demand Response

Reso

urce

Opt

ions

Energy Cost

2018 Irrigation Event

1,500

1,700

1,900

2,100

2,300

2,500

2,700

2,900

3,100

3,300

1:00 AM 3:30 AM 6:00 AM 8:30 AM 11:00 AM 1:30 PM 4:00 PM 6:30 PM 9:00 PM 11:30 PM

7/13/2018 7/13/2018 - Expected

Approx. 300 MW

4 groups 2-4 pm , 3-7 pm , 4-8 pm & 5-9

pm

76 MW74 MW

83 MW66 MW

2 pm

9 pm

MW

2018 AC Cool & Flex Peak Event

1,500

1,700

1,900

2,100

2,300

2,500

2,700

2,900

3,100

3,300

3,500


7/16/2018 - Expected 7/16/2018

30 MW

26 MW

AC Cool Credit 4-7 pm , Flex Peak 4-8 pm

4 pm 7 pm 8 pm

56 MW

MW

2019 IRP Analysis

• We plan to model DR in Aurora as part of the 2019 IRP process.• Modeling properly in Aurora is a challenge.• We have evaluated capacity and program hours using a peak

planning load.

Forecast Peak Days

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000


9 Hours

390 MW

7 Hours

2019

2038390 MW

MW

Future Load Duration Curves

3,000

3,100

3,200

3,300

3,400

3,500

3,600

3,700

3,800

3,900

4,000

4,100

4,200

4,300

4,400

4,500

4,600

0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 160 170 180 190 200

Hours

390 MW

2038

MW

2019 2028 2038max 3,634 4,073 4,544

>>> #hrs 95 74 60 hr 50 3,350 3,755 4,189

diff 284 318 355 hr 60 3,322 3,724 4,154

diff 312 349 390 hr 70 3,294 3,691 4,118

diff 340 382 426

349 MW

312 MW2028

2019

-

50

100

150

200

250

300

350

400

450

- 100 200 300 400 500 600 700 800

Hour

s

Demand Response MWs

Hours Affected

Load Duration Analysis

Hours outside of current program hours

0

5

10

15

20

25

30

35

50 hrs 75 hrs 100 hrs 125 hrs 150 hrs

Top Load Hours

1,500

1,700

1,900

2,100

2,300

2,500

2,700

2,900

3,100

3,300

MW

Idaho Power Total Demand Response July 16, 2010

7/16/2010 W/O DR

150 MW

140 MW

2019 IRP Analysis observations

• System load needs to grow to fully utilize390 MW.

• Expanding DR in the near term would need to focus on different hours.

• This would add customers and cost, but not capacity.

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000


9 Hours

390 MW

2019

7 Hours

2019 IRP proposal

• Our goal: Propose a reasonable amount of incremental DR based on achievability, need and operability

Comfortable could be implemented from a program perspective

Let Aurora select DR up to that amount

• Modeling as resource

• Example – 5 MW per year up to ~ 50 incremental DR (on top of 390 MW we currently have)

Questions/Comments?

EIM IRPAC Meeting

Kathy AndersonTransmission and Balancing Operations Manager

January 10, 2019

Agenda

• What is EIM?

• What EIM is not

• EIM Principle and Tests

• EIM and the IRP

What is EIM?

• An intra-hour centralized energy market used to economically and securely dispatch participating resources to balance supply and load across the market’s footprint (EIM Area) every five minutes.

What is EIM?

• EIM’s priority is to serve load and imbalance at the lowest possible cost (Economic Dispatch).

• Ensure generation, and transmission limitations are respected (Security Constrained).

• Use Bid Ranges (INC/DEC) from voluntarily offered participating resources to determine the most economical and reliable/secure generation to meet load and interchange demands.

What EIM is not

• Capacity and Ancillary Services market (regulation, spin, non-spin, flexible ramping)

• A replacement for current bilateral business and long-term planning obligations of an Entity

• Day-ahead energy market• Hour-ahead energy market• Anything other than an intra-hour real time energy market

What Changes in Resource Planning and Utilization?

Integrated Resource Planning

(20 years)

Risk Management

Process(18 months )

Monthly Balancing

Day-ahead Balancing

Hour-ahead Balancing

Real Time(5-15 minute increments)

• Key change is to real-time, intra-hour scheduling and dispatches

EIM Principle – No Leaning• Entities must pass resource sufficiency tests each hour.• The tests address real time leaning prior to the start of each hour

to ensure the EIM entity is not leaning on the market for capacity, flexibility, or transmission.

• Balancing Test• Bid Capacity Test• Flexible Ramping Sufficiency Test• Feasibility Test (also performed in Day-ahead Market)

• Passing the tests ensures the EIM entity is able to meet its reliability obligation as a stand-alone entity without market support.

EIM Principle – No Leaning

• Balancing Test: Ensures each EIM Entity is balanced with resources to meet the forecasted load demand of its area before each hour.

• Bid Capacity Test: Ensures sufficient EIM Participating Resource capacity bid range through incremental or decremental energy bids above or below the Base Schedules to meet the imbalance.

EIM Principle – No Leaning

• Flexible Ramping Sufficiency Test: Ensures that each balancing area has enough ramping resources across each hour to meet expected upward and downward ramping needs (must cover Expected Load + “uncertainty”)– “Uncertainty” is an estimate of unforeseen variations in VERs and Load.

• Feasibility Test: Information test to notify EIM Entity if base schedules submitted are transmission feasible according to the market model.

EIM and IRP

• EIM values flexibility in real time. Fast-moving available resources are important.

• Entities must ensure flexibility exists on their own systems to meet their own needs to be operating in the energy imbalance market.

• Long-term planning ensures we are sufficient to meet Idaho Power’s obligation for reliable service (capacity, reserves, flexibility).

• EIM is not a replacement for long- and short-term planning.

Questions?

Balancing Load, Wind, and SolarRegulating Reserves

IRP Advisory Council Meeting

January 10, 2019

NERC BAL-001-2Real Power Balancing Control Performance

• NERC standard:– Each Balancing Authority shall operate such that its clock-minute average of

reporting Area Control Error (ACE) does not exceed its clock-minute Balancing Authority ACE Limit (BAAL) for more than 30 consecutive clock minutes.

– ACE cannot exceed BAAL for more than 30 consecutive minutes.– ACE is managed through system flexibility.

• Dispatchable ramping of generating units– Natural Gas capacity– Hydro capacity– Coal capacity

NERC BAL-001-2Real Power Balancing Control Performance

• Historical load, wind and solar data– December 2016 through November 2017

• How much system flexibility (i.e., RegDn & RegUp) would have brought about compliance with NERC reliability standard?

Managing ACE

Regulating Reserve Rules

• Dynamic– Function of:

• Season (DJF, MAM, JJA, SON)• Load base schedule• Load bin (i.e., TOD)• Wind base schedule• Solar base schedule

• Rules for simulations• Rules are designed to reflect compliance with NERC reliability

standard (i.e., adherence to rules is expected to enable compliance).

Derivation Steps

1. Determine RegUp/RegDn for load to comply with NERC reliability standard

2. Determine RegUp/RegDn for wind to comply with NERC reliability standard

3. Determine RegUp/RegDn for solar to comply with NERC reliability standard

4. Determine RegUp/RegDn sharing or allocation factors for net load (load minus wind minus solar) to comply with NERC reliability standard

Hour 16:00-17:00 in June

Regulating Reserve Rules – Spring (March-May)

Regulating Reserve Rules – Summer (June-August)

Regulating Reserve Rules – Fall (September-November)

Regulating Reserve Rules – Winter (December-February)

Reg Rules – IRP Approximations

• For a given hour:– RegUp = (A% × Load MW) + (B% × Wind MW) + (C% × Solar MW)– RegDown = (D% × Load MW)

• Approximations to accommodate LTCEs with added solar and wind capacity

Aurora Modeling Update

Scott WrightLead Planning Analyst

January 10, 2019

Aurora Simulations

• Long-term Capacity Expansion (Optimized Portfolios)

• Portfolio Analysis

• Risk Simulations

Natural Gas Price Forecast CONFIDENTIAL--This page left blank

Carbon Price Forecast

$0

$20

$40

$60

$80

$100

$120

2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038

$/To

n

Zero Planning High Generational

Optimized Portfolio Matrix

Non-B2H Zero Carbon Planning Carbon Generational Carbon

High Carbon

Planning Gas 1 2 3 4

EIA Reference 5 6 7 8

EIA LOG 9 10 11 12

B2H Zero Carbon Planning Carbon Generational Carbon

High Carbon

Planning Gas 13 14 15 16

EIA Reference 17 18 19 20

EIA LOG 21 22 23 24

• 4 Additional Jim Bridger Portfolios

Optimized Portfolio Matrix(continued)

Planning Gas / Planning Carbon Unit Retirements YE 2021 & 2022 SCR

Non-B2H 25 26

B2H 27 28

• 28 Portfolios will be analyzed under the following scenarios:– 4 scenarios for each Optimized Portfolio.

Portfolio Analysis

Portfolio -- Planning Carbon High Carbon

Planning Gas X X

High Gas X X

• Portfolios will be stressed under the following scenarios:

Risk Analysis

Portfolio --

Natural Gas Prices X

Hydro Generation X

Carbon Prices X

Demand X

Aurora New Resource Shapes

• Aurora New Resources Table assumptions:– Aurora supplied hourly Wind shapes are used for Idaho and Wyoming Wind.– PV Watts is used for Utility Scale and Residential Solar shapes.

• pvwatts.nrel.gov

https://pvwatts.nrel.gov/

Wind Shape (First week in April)

0102030405060708090

100

Nam

epla

te P

erce

ntag

e

Hours

Wyoming Idaho

Solar Shape (First week in July)

0

10

20

30

40

50

60

70

80

90

100

Nam

epla

te P

erce

ntag

e

HoursUtility Scale Residential Fixed

Aurora Batteries

• Two types of batteries are included in the Aurora New Resources table.– 4 hour Lithium Ion stand-alone battery – grid charged

• 5 MW– 4 hour Lithium Ion paired with 40 MW solar facility – solar charged

• 10 MW, 20 MW, 30 MW

• Battery Characteristics– 85% efficiency rating– Discharge target period – Demand net must-run resources

• Example must-run resources: Wind, Solar, PURPA– Able to provide regulation services

Battery Example (1 day in July)(5 MW Grid Charged)

-8

-6

-4

-2

0

2

4

6

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

MW

Hours

Charge

Discharge

DRAFT Supply-Side Resource Operating Inputs

TechnologyNameplate (MW AC)

2023Plant Capital

($/kW)/Source*

Fixed O&M($/kW per month)

Variable O&M

($/MWh)

2023 Transmission Capital ($/kW)

Annual Capacity Factor

Economic Life(Years)

2023Integration

Charge ($/MWh)2023 LCOE ($/MWh)**** Other

Boardman to Hemingway (350 MW)

Inbound: 350 MW avg.**

$0 $0.42 $0.00 $696/IPC 33%*** 55 N/A — Mid-C wholesale electric market

Geothermal (30 MW)

30 $6,495/ NREL est.

$16.42 $0.00 $164 88% 25 N/A $148

Biomass—Anaerobic Digester (35 MW)

35 $3,902/ Electrigaz est.

$3.42 $18.23 $164 85% 30 N/A $104 No fuel cost included in LCOE

SCCT—Frame F Class (170 MW)

170 $1,009/ NREL est.

$1.17 $8.18 $133 5%*** 35 N/A $398 Heat rate (HR) = 9,720 Btu/kWh

Reciprocating Gas Engine (55.5 MW)

55.5 $1,077/ vendor est.

$1.09 $5.92 $128 15%*** 40 N/A $167 HR = 8,300 Btu/kWh

Reciprocating Gas Engine (111.1 MW)

111.1 $959/ vendor est.

$1.09 $5.92 $128 15%*** 40 N/A $157 HR = 8,300 Btu/kWh

CCCT (1x1) F Class (300 MW)

300 $1,182/ NREL est.

$1.01 $3.17 $112 60%*** 30 N/A $72 HR = 6,420 Btu/kWh

Small Modular Nuclear (60 MW)

60 $4,683/ vendor est.

$0.76 $2.28 $755 90%*** 40 N/A $137 HR = 11,493 Btu/kWh; costs for 2023 online date, however IRP assumes nuclear resource not available prior to 2026

Solar PV—Utility-Scale 1-Axis Tracking (40 MW)

40 $1,334/ NREL est.

$0.93 $0.00 $164 26% 30 $0.63 $68 Investment tax credit (ITC) eligible; LCOE includes 10% ITC

Solar PV—Residential Rooftop Variable $2,947/ NREL est.

$1.50 $0.00 $0 21% 25 N/A $186

Solar PV—Commercial Rooftop Variable $2,160/ NREL est.

$1.30 $0.00 $0 21% 25 N/A $138

Solar PV—Targeted Siting for Grid Benefit (0.5 MW)

0.5 $1,734/ NREL est.

$0.93 $0.00 $ (62) 26% 30 N/A $79 ITC eligible; negative transmission cost to reflect T&D benefit; LCOE includes 10% ITC

Solar PV (40 MW)—AC Coupled with Lithium Battery (10 MW/40 MWh)

50 $1,575/ NREL est.

$0.91 $2.70 on battery output

$164 ≈22% (50 MW total project

capacity)

30 (solar)20 (battery w/replace

after 10 years)

$0.00 $92 85-90% roundtrip (RT) efficiency (battery); ITC eligible; LCOE includes 10% ITC; AC-coupled with recharge from PV


60 $1,735/ NREL est.



capacity)


after 10 years)

$0.00 $122 85-90% RT efficiency (battery); ITC eligible; LCOE includes 10% ITC; AC-coupled with recharge from PV


70 $1,849/ NREL est.



capacity)


after 10 years)

$0.00 $155 85-90% RT efficiency (battery); ITC eligible; LCOE includes 10% ITC; AC-coupled with recharge from PV

Small Hydro Variable $4,000–8,400/NREL est.

±$7 $0.00 Site dependent Site dependent 75 N/A

Storage—Pumped Hydro (500 MW/4,000 MWh)

500 $1,964/ NREL est.

$0.36 $0.00 $209 16%*** 75 N/A $183 75–82% RT efficiency; LCOE does not include recharge costs

Storage—Lithium Battery 4 Hours (5 MW/20 MWh)

5 $1,813/ NREL est.


Storage—Lithium Battery 8 Hours (5 MW/40 MWh)

5 $2,947/ NREL est.


Wind Wyoming (100 MW)

100 $1,722/ NREL est.

$4.73 $0.00 $133 45% 25 $20.29 $96

Wind Idaho (100 MW)

100 $1,722/ NREL est.

$4.73 $0.00 $133 35% 25 $20.29 $116

2019 Integrated Resource Plan

Note: Costs are nominal assuming 2023 on-line date. Note nuclear resource assumed not available prior to 2026.

*Includes engineering, procurement and construction (EPC), and other owner's costs; **500 MW Apr–Sep, 200 MW Oct–Mar;***Capacity factors are estimated for resources whose dispatch is affected by variable operating costs or wholesale market purchase costs.****LCOE provides approximate comparison of resource economics when considering resources providing similar grid service. Comparison of LCOE across technologies is often problematic and can be misleading in assessing economic competitiveness. LCOE is not an input to Aurora modeling performed for the IRP. Wind/solar integration costs are included in provided LCOE, but are not included in Aurora modeling; Aurora modeling imposes regulating reserves necessary to integrate wind/solar. LCOE for CO2 emitting resources does not include carbon costs; carbon cost scenarios are included in Aurora modeling.

2019 IRP Advisory Council Meeting January 10, 2019 · 3. Determine RegUp/RegDn for solar to comply...

Documents

Transcript of 2019 IRP Advisory Council Meeting January 10, 2019 · 3. Determine RegUp/RegDn for solar to comply...