bpa resource program draft results...9:15 - 10:15 60 mins recap of model inputs: • load forecast...
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B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
BPA Resource Program
Draft Results
May 10, 2018
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Agenda
2 Draft - For Discussion Purposes Only
Time Mins Agenda Item
9:00 - 9:10 10 mins Introductions and Agenda Review
9:10 - 9:15 5 mins Project Overview
9:15 - 10:15 60 mins Recap of Model Inputs:
• Load Forecast
• CPA
• DR Potential Assessment
10:15 - 10:45 30 mins Needs Assessment Overview and Results
10:45 - 10:55 10 mins Break
10:55 - 11:15 20 mins Overview of Optimization Model
11:15 - 11:50 35 mins Draft Outputs and Results
11:30 - 11:45 10 mins Wrap Up and Next Steps
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
BPA Resource Program The BPA Resource Program
• Begins with a forecast of BPA load obligations and existing resources and then determines
needs
• Identifies and evaluates potential solutions to meeting those needs
• Energy efficiency, demand response, market purchases, wind, solar, gas plants, etc.
• Outlines potential strategies for meeting those needs
The Resource Program is not
• A decision or policy document such as an Administrator’s Record of Decision
• A requirement of law or a regulating body such as FERC or NERC
3 Draft - For Discussion Purposes Only
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Resource Program Overview
4 Draft - For Discussion Purposes Only
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Previous Workshops
Kick Off Meeting – March 2017
End Use Load Forecast – June 2017
CPA Kick off – May 2017
CPA Methodology – September 2017
Needs Assessment and Optimization Model Methodology – November 2017
CPA Results Brownbag – March 2018
5 Draft - For Discussion Purposes Only
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
End Use Load Forecast
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Implementing End-Use Forecasting Goal: Implement End-Use forecasting to provide a frozen efficiency forecast for the BPA
Resource Program
• Process that is transparent to and involves our customers
• Consistency with the Council forecast data
• Representative of the BPA Power contractual obligation
• Integrates with our other BPA forecasting and planning activities
Results: Contracting and Schedule complications required a small implementation in 2017
• Eleven customers had end-use (Statistically Adjusted End-use) models created due to
delay on ITRON product
• Remaining approximate 140 used existing time series process on pre-conservation
energy
Draft - For Discussion Purposes Only 7
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Forecast results Frozen Efficiency
forecast 2018-2040
annual growth rate
averages 0.9%
Approximately 600
aMW different in
2040
Both will change as
we refine the
forecasting method
over time
8 Draft - For Discussion Purposes Only
0
2000
4000
6000
8000
10000
12000
aMW
Frozen Efficiency and 2017 Expected Case
Frozen Efficiency
Expected Case
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
SAE Methodology Benefits
We learned and confirmed several things during this implementation process
• The process leverages work already done in the region using Council modeling
details while tailoring it to the BPA service territory
• The requisite review of the forecast is more thorough because of additional
assumptions to consider
– Leads to a comprehensive review of economy activity by BPA staff
– Review of additional assumptions when having local area discussions about
the forecast
– Augments thought process used in econometric approach
• Results are very utility specific
Draft - For Discussion Purposes Only 9
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Items to address over time
Model Council forecast using this approach and see what results it produces to
make sure we calibrate correctly to Council details
Determine method to provide link and details for future Conservation Potential
Assessments
More work on customer specific reliable detail/data
Create common vocabulary in region
Arrange for details on distributed generation
Work on data sources to leverage for or develop transmission level detail
Draft - For Discussion Purposes Only 10
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Needs Assessment
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Needs Assessment Overview The Needs Assessment provides forecasts of Federal system energy, capacity, and
balancing reserve needs
• Considers federal system resources and load obligations
These results inform later steps of the Resource Program process
The Needs Assessment methodology is largely unchanged from previous
Resource Programs
• Expanded to a 20 year continuous forecast
• Updated to a frozen efficiency load forecast
12
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Needs Assessment Metrics Annual Energy
• Evaluates the annual energy surplus/deficit under 1937-critical water conditions
P10 Heavy Load Hour
• Evaluates the 10th percentile (P10) surplus/deficit over heavy load hours by month, given variability
in hydro generation, loads, and Columbia Generating Station output
P10 Superpeak
• Evaluates the P10 surplus/deficit over the six peak load hours per weekday by month, given
variability in hydro generation, loads, and Columbia Generating Station output
18-Hour Capacity
• Evaluates the ability to meet the six peak load hours per day over three-day extreme weather
events assuming median water conditions
Balancing Reserves
• Evaluates the ability to meet forecasted balancing reserve demand in the BPA balancing authority
area
13
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Results Summary – Energy Annual Energy deficits begin in fiscal year (FY) 2021 and grow to 850 aMW by 2039
The largest P10 Heavy Load Hour deficits occur in winter, the first half of April, and fall
• January has the largest deficits (650 aMW in FY 2020 and 1,850 aMW in FY 2039)
The largest P10 Superpeak deficits occur in winter, the first half of April, and late
summer/fall
• Near load-resource balance in FY 2020 and deficits grow to 1,000 aMW by FY 2039
• The P10 Superpeak deficits are smaller than the P10 Heavy Load Hour deficits in most
months, with the second halves of April and August being the exceptions
14
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Results Summary – Capacity & Reserves
Winter is 18-Hour Capacity surplus over the study horizon, while summer is surplus in
FY 2020 and deficit thereafter (550 MW in FY 2039)
• The summer 18-Hour Capacity deficits are smaller than the P10 Superpeak deficits
Demand for balancing reserves in the BPA balancing authority area is not expected to
reach 900 MW of incremental reserve over the study horizon
15
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Results: Annual Energy
Key assumptions:
• Hydro generation based on 1937-critical water conditions
• Loads and Columbia Generating Station output reflect expected values 16
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Results: P10 Heavy Load Hour
Key assumptions:
• Variability in hydro generation, loads, and Columbia Generating Station output
17
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Results: P10 Superpeak
Key assumptions:
• Variability in hydro generation, loads, and Columbia Generating Station output
18
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Results: 18-Hour Capacity
Key assumptions:
• Hydro generation based on median water
conditions
• Loads based on three-day extreme weather
event
The 2015 Needs Assessment had surpluses of:
• 1,150 MW in winter
• 250 MW in summer
19
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Results: Balancing Reserves There is considerable uncertainty in future demand for balancing reserves, which includes:
• Amount and location of wind and solar development in the region
• Scheduling practices and elections
• Elections to self-supply
• New or expanded markets
• Departure of existing resources
However, market conditions and RPS forecasts suggest future balancing reserve demand is
unlikely to reach 900 MW of incremental reserve
Will continue to monitor the balancing reserves landscape and address the issue as
warranted in future Needs Assessments
20
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Needs Assessment Conclusion
Overall, the results demonstrate that BPA is energy (fuel) limited
• P10 Heavy Load Hour deficits are larger than P10 Superpeak deficits in most months
• P10 Superpeak deficits are larger than 18-Hour Capacity deficits
The most notable change from the 2015 Needs Assessment results is that the current
studies forecast summer 18-Hour Capacity deficits for most of the study horizon
21
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Conservation Potential
Assessment
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Overview BPA has historically relied on the Council’s Power Plan for its assessment of
conservation potential in public power
It is becoming increasingly important to have EE potential data specific to BPA
• In addition to Resource Program, the non-wires and Integrated Planning efforts
BPA hired Cadmus to complete a BPA specific Conservation Potential Assessment
• Based on Council’s methodology
• Updated for changes since the passing of the 7th Plan (2016)
23 Draft - For Discussion Purposes Only
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Study Horizon
Seventh Plan: 2016-2035
Resource Program: 2020-2039
Conservation Potential Assessment
24
2016 2020 2035 2039
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Methodology Started with the 7th Plan baseline and measures
Updated for:
• New codes and standards
• Expired measures
• Measures changes from RTF
• New Measures
• Savings accomplishments – 2016-2019
Applied BPA specific characteristics (RBSA, CBSA, EIA)
Estimated technical achievable potential
25 Draft - For Discussion Purposes Only
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Reminder
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Key Findings
1 2
• Look slightly different from the region
3 • Identified a significant amount of
inexpensive energy efficiency
• The results were mostly as expected
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Things We Learned about Public Power
01
02
03
04
05
06
Have more electric heating load
Have 38% of all single family homes
Have 36% of all commercial sq footage
Have 48% of the industrial sales
Have 34% of all irrigated acres
Have 30% of substations > 40,000 MWh
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Total Savings Potential
20 Year Cumulative Savings Potential
Sector aMW % of Total Potential
Agriculture 39 2% Commercial 542 30%
Utility 67 4% Industrial 243 13%
Residential 920 51% Total 1,812 100%
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Energy Efficiency Supply Curve
30 Draft - For Discussion Purposes Only
474
614
796
902 988
1,055 1,088 1,171
1,329 1,367 1,403 1,446 1,475 1,477 1,504
1,588 1,621 1,670 1,670 1,670
1,812
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
Under$5
Under$10
Under$15
Under$20
Under$25
Under$30
Under$35
Under$40
Under$45
Under$50
Under$55
Under$60
Under$65
Under$70
Under$85
Under$100
Under$115
Under$130
Under$145
Under$160
Over$160
Cumulative 20-Year Potential - aMW
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Energy Efficiency - Inputs
Conservation potential provided to optimization model in 90 bundles
31 Draft - For Discussion Purposes Only
12 Levelized
Cost Bundles Six End Uses
Retrofit and
Lost
Opportunity
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Demand Response Potential
Assessment
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
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33
DR Potential Agenda
1. Overview and purpose
2. Basis for estimates
3. Estimate of DR Potential
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
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1. Overview and Purpose
• This is the supply side (amount, cost) of DR over a 20 year horizon
with an expected seven year ramp
• This is not the needs or requirements side of the equation
• This is not a study of 2018 DR Potential or 2018 DR Costs
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
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35
Overview and Purpose (Continued)
• This study was intended to fulfill the request for a DR Potential Assessment in
the 7th Power Plan
• Be a useful tool for BPA Resource Planning
• And it was expanded to include BPA Non-wires potential 2017 locational
considerations
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
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36
Demand Response Potential Study
Geography (Primary): - BPA public power portion of the region.
- I-5 Corridor/West of Cascades and East of
Cascades.
- Six geographical areas, as defined by
transmission planning.
Scope: - All BPA preference customers.
Timing: - 20-year potential estimates.
- Aligns with Resource Program and CPA.
Inputs: - Interviews w/ 162 stakeholders (incl. 52 BPA
power customers) and 454 surveys.
- National and regional cost benchmarking.
Background:
In the 7th Plan’s Action Plan, the Council recommended that the BPA conduct a study
of DR potential and an assessment of barriers. The 2018 BPA Power Resource
Program will model DR as an input.
The study helps answer these questions for BPA:
How cost competitive is DR as an alternative for power (e.g.
future peaks) and for transmission (e.g. build deferrals)?
How much (MWs) DR is there in BPA service territory and what
will it take to get it?
BPA contracted and selected the Cadmus Group LLC (Cadmus) to perform this work. In
addition to the Potential Assessment and Barriers Assessment, Cadmus performed a
companion Elasticity Study .
DR Study Parameters
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
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37
Scope of DR Analysis
BPA Preference Customer Peak Demand (2016) BPA Preference Customer Energy Sales (2016)
The analysis included all BPA Power preference customers, including federal agencies, direct-service industrial customers, tribal utilities, federal irrigation districts, and one port
district. Figures above did not display 10 customers because their map boundaries were not available in BPA-sourced maps.
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
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38
2. Basis for Estimates
• Considered East vs. West in Pacific Northwest
• Comparison of DR across USA and in Pacific Northwest
• DR costs are based on similar programs and achievable rates of
adoption
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
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39
BPA Firm Power Customer Hourly Load
Duration, East vs. West (2016)
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
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40
DR Resources in Wholesale Markets of
RTOs/ISOs and Peak Load Reduction
Note: None of these markets for DR are unconstrained; DR targets are pre-determined which limits the total amount of DR resources. Values are typical average
within each area.
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
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41
DR Capability as Percent of Peak Load –
Public Utilities (2015)
Note: Few utilities reporting DR to EIA are unconstrained. Almost all of the DR reported is target-driven; reports indicate what utilities choose to do, not what is
possible to accomplish.
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
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42
3. Estimate of DR Potential
• Multiple DR products modeled using current technologies (and costs)
• Uses Ramp of 7 years, then overall 20 year levelized cost estimates*
• Sectors – Residential, Commercial, Industrial, Utility, Agricultural (DR
products have different costs)
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
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43
Base Case Achievable Potential
The base case was developed by benchmarking research participation rates of common programs. These participation rates are generally a median
value and are intended to depict participation in a healthy, established DR program. Most of the products reach a full ramp within 7 years, and after
that grow with anticipated load rate changes.
The base case values represent the mean of a range.
Area Winter Achievable
Potential (MW)
Percent of Area
System Peak—
Winter
Summer Achievable
Potential (MW)
Percent of Area
System Peak—
Summer
West 1,061 9.9% 807 10.8%
East 490 9.6% 795 13.5%
Total 1,551 9.8% 1,602 12.0%
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
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44
DR Products Modeled Sector DR Product Deployment Mechanism Seasonality
Residential
DLC—Water Heating DLC Summer and winter
DLC—Space Heating DLC Winter only
DLC—Central Air Conditioning (CAC) DLC Summer only
DLC—Smart Thermostats DLC Summer and winter
Critical Peak Pricing (CPP)* Tariff-Based Summer and winter
Behavioral DR Direct Communication
(e.g., event notifications) Summer and winter
Commercial**
DLC—CAC DLC Summer only
Lighting Controls Automated Response Summer and winter
Thermal Storage Cooling Storage Summer only
Industrial*** Real Time Pricing (RTP)* Tariff-Based Summer and winter
Commercial and Industrial Demand Curtailment and DLC Contract (Automated or Manual Response) Summer and winter
Interruptible Tariff Tariff-Based Summer and winter
Agricultural Irrigation DLC DLC Summer
Utility System Demand Voltage Reduction (DVR) SCADA Summer and winter
*Cadmus assumed that Time of Use (TOU) rates were already in place. **In this assessment, Cadmus included public buildings in the commercial sector. ***In this assessment, Cadmus included public process loads such as municipal water treatment plants in the industrial sector.
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
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45
Base Achievable DR – Product View
* The total achievable potential values in this detailed potential by product table do not match those in the previous slide because estimated achievable potential for DSI customer was estimated independently.
Product Winter Achievable
Potential (MW) Percent of Area System
Peak - Winter Levelized Cost ($/kW-
year) Summer Achievable
Potential (MW) Percent of Area System
Peak - Summer Levelized Cost ($/kW-
year)
Residential DLC—Space Heating 206 1.3% $53 0 0.0% n/a Residential DLC—Water Heating 389 2.5% $122 285 2.1% $167 Residential DLC—CAC 0 0.0% n/a 113 0.8% $74 Residential DLC—Smart Thermostat 222 1.4% $47 120 0.9% $88 Residential CPP 168 1.1% $10 57 0.4% $12 Residential Behavioral DR 37 0.2% $110 13 0.1% $111 Commercial DLC—CAC 0 0.0% n/a 110 0.8% $29 Commercial Lighting Controls 44 0.3% $32 55 0.4% $32 Commercial Thermal Storage 0 0.0% n/a 9 0.1% $51 C&I Demand Curtailment 184 1.2% $85 205 1.5% $85 C&I Interruptible Tariff 62 0.4% $73 69 0.5% $73 Industrial RTP 5 0.0% $35 5 0.0% $34 Agricultural Irrigation DLC 0 0.0% n/a 420 3.1% $44 Utility System DVR 225 1.4% $11 133 1.0% $12 Total 1,541 9.8% 1,592 11.9%
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
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46
Winter Base Achievable Potential
Note: Displayed costs are the sum of annual costs, levelized over the 20-year study planning horizon, from the total resource cost perspective.
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
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47
Summer Base Achievable Potential
Note: Displayed costs are the sum of annual costs, levelized over the 20-year study planning horizon, from the total resource cost perspective.
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Additional Resources
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
In Addition to EE and DR
The optimization also considered
Market Reliance – How many purchases can be made from the market, where
the assumed market depth was determined by a supporting analysis and
changes by HLH/LLH, month and year for the full duration of the study
Solar – Fixed-axis and single-axis
Wind – Assigned attributes representative of Columbia Basin wind resources
Peaking Gas Plant – An LMS 100; GE’s popular aero-derivative gas plant
49 Draft - For Discussion Purposes Only
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Optimization Model
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
51 Draft - For Discussion Purposes Only
Optimization Model Overview All resource options are evaluated against
our market price forecast on an hourly
basis for each risk iteration (Performance
Run). The optimization then:
1) Solves for portfolio of resources that
satisfy needs at the lowest cost
(Portfolio 1).
2) Produces 39 additional portfolios by
gradually increasing the budget constraint
and minimizing total cost variation. This
generates higher cost portfolios that
include resources better aligned with
BPA’s energy needs, lowering BPA’s
exposure to the market.
Market Price
Forecast
Needs Assessment
(HLH & Summer Capacity)
Market Limits
All Available
Options
Performance
Run Optimization
Portfolio 2
Portfolio 3
Portfolio 4
Portfolio 5
Portfolio 6
Portfolio 7
Portfolio 8
Portfolio 9
Portfolio 10
Portfolio …40
Portfolio 1
AURORA Process
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Additional Modeling Considerations Optimization results reflect assumptions that some resource options have negative costs
Various benefits have been quantified and netted off total resource fixed costs, in some cases
benefits are sufficient to bring fixed costs below 0.
Additionally, we are surplus energy on average and allow the model to sell all surplus energy at
the market price when its not needed to meet our needs. This expected revenue drives down
total portfolio cost.
Caveats:
• Portfolio values independent of rate impacts or actual expenditures required to acquire the
resource options
• Market prices are exogenous – they do not adjust as more purchases / sales are made
• Only one acquisition decision point modeled for all EE and DR programs (2020)
• We are not modeling the potential for new resources to alter hydro operations
• Did not include winter DR products because we do not have winter capacity needs
52 Draft - For Discussion Purposes Only
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Market Limits in AURORA
Given longer duration of this Resource Program and expected evolution of resource mix over the planning horizon,
we have adopted a method that relies on AURORA. In order to ascertain market depth:
1. Start with our base resource build used to project future marginal costs of meeting load (market prices), this
meets a 15% planning reserve margin in the PNW
2. Simulate scarcity conditions by reducing PNW hydro generation to monthly p10 level and allow all other risk
models to operate normally (loads, transmission, wind, CGS, and natural gas prices)
3. Add incremental load increases to approximate greater resource retirements / fewer resource additions
associated with higher levels of regional market reliance
4. On a monthly basis, determine level at which greater market reliance causes region to exceed 5% LOLP (as
roughly approximated with AURORA)
5. Allocate a share of the market reliance to BPA and accept this as our market reliance limit
53 Draft - For Discussion Purposes Only
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Market Limits in AURORA
Start with baseline loads and
resources
This approach focuses on
physical load-resource
balance across the
system, no modifications
have been made to reflect
frictions / improvements
driven by changing market
structures
Incrementally increase
PNW regional loads until
loss-of-load events exceed
threshold
(5% LOLP)
Determine BPA’s share
(proportional to BPA load
obligation / PNW regional
loads) and use this as our
market reliance limit
54 Draft - For Discussion Purposes Only
BPA
PNW Loads PNW Loads
PNW Loads
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
AURORA HLH Market Limits*
55 Draft - For Discussion Purposes Only
0
500
1000
1500
2000
2500
Jan
Mar
May Ju
l
Sep
No
v
Jan
Mar
May Ju
l
Sep
No
v
Jan
Mar
May Ju
l
Sep
No
v
Jan
Mar
May Ju
l
Sep
No
v
Jan
Mar
May Ju
l
Sep
No
v
Jan
Mar
May Ju
l
Sep
No
v
Jan
Mar
May Ju
l
Sep
No
v
Jan
Mar
May Ju
l
Sep
No
v
2020 2021 2022 2023 2024 2025 2030 2035
*In our analysis, no loss of load events occurred in LLH
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Outputs and Findings
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Resource Solutions - Efficiency Frontier
57 Draft - For Discussion Purposes Only
$100
$110
$120
$130
$140
$150
$160
$170
$180
Po
rtfo
lio
To
tal C
ost
Sta
nd
ard
Devia
tio
n
(Mil
lio
ns
, N
PV
)
Portfolio Total Cost (Millions, NPV)
Individual Portfolios
“Efficient” means that, at any given cost level, the indicated portfolio represents the one mix of resources which
minimizes cost variance. Being on the Efficiency Frontier does not indicate equality amongst portfolios.
• Every portfolio meets our needs
• The model starts by determining the least cost portfolio
• $160M (over 20 years) is then added to each portfolio cost
• The model then reduces the variability in costs with different resource combinations given the new
cost levels
• Due to lower market exposure and electricity price levels, the reductions in cost variability are relatively
minor compared to the additional cost
Least Cost
Least Cost Variability
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Efficiency Frontier
58 Draft - For Discussion Purposes Only
$100
$110
$120
$130
$140
$150
$160
$170
$180
Po
rtfo
lio
To
tal C
ost
Sta
nd
ard
Devia
tio
n
(Mil
lio
ns
, N
PV
)
Portfolio Total Cost (Millions, NPV)
Point where spending more money does not reduce variable cost exposure
Portfolios to the right could require a 6(c) process
1
2
3
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Resource Program Outputs – 2020/21
59 Draft - For Discussion Purposes Only
2020-2021 Totals
Portfolio
Maximum Market Purchase
(aMW) EE Aquired
(aMW)*
Highest EE Cost Bundle
Demand Response
(MW)
1 775 121 $25/MWh 40
2 737 154 $40/MWh 131
3 729 161 $50/MWh 131
Changes Across Portfolios
Change Total Market
Purchase
Total EE
2 year
Total DR
2 year
1 2 -38 33 91
2 3 -8 7 0
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
60 Draft - For Discussion Purposes Only
Market
Purchase Market
Sales
P10 HLH
Energy Need
Monthly HLH Portfolio Energy vs P10 Need
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Anything else?
61 Draft - For Discussion Purposes Only
Monthly HLH Market Reliance vs Market Reliance Limit
Market Reliance
Limit
Positive values
indicate market
purchases
Portfolio 1
Portfolio 2
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Demand Response Observations
62 Draft - For Discussion Purposes Only
Portfolio 2
Portfolio 1
MW
Notes: • 40 MW by 2021
• 208 MW by 2025
• Is due its contribution to meeting
summer capacity needs in the
least cost portfolio
• Portfolios 2-3
• Additional DR is added primarily
to reduce to cost variance
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
EE Portfolio Supply Curves
Model takes all savings up to $20
in every portfolio
To reduce cost variance, model
begins to move up EE supply
curve
Focuses on residential windows,
insulation and heat pumps in
higher cost bins
63 Draft - For Discussion Purposes Only
0
20
40
60
80
100
120
140
160
180
$0/MWh andUnder
$0.01/MWh to$10/MWh
$10.01/MWhto $20/MWh
$20.01/MWhto $25/MWh
$25.01/MWhto $30/MWh
$30.01/MWhto $35/MWh
$35.01/MWhto $40/MWh
$40.01/MWhto $50/MWh
$50.01/MWhto $60/MWh
$60.01/MWhto $80/MWh
$80.01/MWhto $100/MWh
Over$100/MWh
aMW
Cumulative Levelized Cost by Portfolio
Port 1 Port 2 Port 3
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Portfolio 1 Acquisitions by End Use
64 Draft - For Discussion Purposes Only
0
200
400
600
800
1000
1200
$0/MWh andUnder
$0.01/MWh to$10/MWh
$10.01/MWhto $20/MWh
$20.01/MWhto $25/MWh
$25.01/MWhto $30/MWh
$30.01/MWhto $35/MWh
$35.01/MWhto $40/MWh
$40.01/MWhto $50/MWh
$50.01/MWhto $60/MWh
$60.01/MWhto $80/MWh
$80.01/MWhto $100/MWh
Over$100/MWh
Portfolio 1 Cumulative Savings - aMW
ELECTRONICS HVAC INDUSTRIAL LIGHTING OTHER WATER_HEATING
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Portfolio 2 Acquisitions by End Use
65 Draft - For Discussion Purposes Only
0
200
400
600
800
1000
1200
$0/MWh andUnder
$0.01/MWh to$10/MWh
$10.01/MWhto $20/MWh
$20.01/MWhto $25/MWh
$25.01/MWhto $30/MWh
$30.01/MWhto $35/MWh
$35.01/MWhto $40/MWh
$40.01/MWhto $50/MWh
$50.01/MWhto $60/MWh
$60.01/MWhto $80/MWh
$80.01/MWhto $100/MWh
Over$100/MWh
Portfolio 2 Cumulative Savings - aMW
ELECTRONICS HVAC INDUSTRIAL LIGHTING OTHER WATER_HEATING
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Which measures reduce cost variance?
Green: industrial
energy management
Red: residential
ductless heat pumps,
windows and
insulation
66 Draft - For Discussion Purposes Only
0
50
100
150
200
250
$0/MWh andUnder
$0.01/MWh to$10/MWh
$10.01/MWh to$20/MWh
$20.01/MWh to$25/MWh
$25.01/MWh to$30/MWh
$30.01/MWh to$35/MWh
$35.01/MWh to$40/MWh
$40.01/MWh to$50/MWh
$50.01/MWh to$60/MWh
$60.01/MWh to$80/MWh
$80.01/MWh to$100/MWh
Over $100/MWh
Cumulative Savings Additions – Portfolio 1 to 2 (aMW)
ELECTRONICS HVAC INDUSTRIAL LIGHTING OTHER WATER_HEATING
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
What We Learned
BPA can continue to meet its needs with a combination of energy efficiency and
market purchases – no need for a major resource
Demand Response appears to be an economically feasible option to summer
capacity needs
All energy efficiency below market prices contribute to a least cost portfolio
Not all savings are equal, measures shaped to meet Bonneville needs are
preferred over other savings
The portfolio of savings selected differs from the current portfolio of savings
achievements
67 Draft - For Discussion Purposes Only
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Next Steps for EE
BPA’s EE portfolio is a balance of many
objectives
The results of the Resource Program
have provided Bonneville with new
information to consider in program
development
Currently developing a proposal for how
to best address these objectives for the
2020/21 rate period
• June 12 Council Meeting
• June 21 IPR workshop
68 Draft - For Discussion Purposes Only
Equity
BPA Needs
Budget
Emerging Technology
Regional goals
Customer Service
EE
Portfolio
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Next Steps Public Comment Period
• May 11- June 1
Finalize Resource Program
• July
69 Draft - For Discussion Purposes Only
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Appendix
70 Draft - For Discussion Purposes Only
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Appendix: P10 Heavy Load Hour (last 10 years)
Key assumptions:
• Variability in hydro generation, loads, and Columbia Generating Station output
71
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Appendix: P10 Superpeak (last 10 years)
Key assumptions:
• Variability in hydro generation, loads, and Columbia Generating Station output
72
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Click to edit Master title style
73
DR Barriers Assessment
• While the DR Potential study provides a supply curve (amount, cost), the Barrier
Study considers barriers to adoption and mitigation strategies
• These two are Complementary Studies
• Barriers Study briefed earlier (key slide provided)
• Both based on strong research methods
B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
Click to edit Master title style
74
Barriers to DR Development
Barrier
Demand Response Distributed Generation Energy Storage
SME n=17
STK n=12
PC n=25
DSP n=7
SME n=16
STK n=12
PC n=25
DSP SME n=16
STK n=12
PC n=24
DSP n=4
Economic/Market
Lack of power customer business case 65% 75% 73% 86% 56% 83% 72% 81% 83% 76% 75%
Lack of clearly defined need/value to BPA 59% 42% 64% 100% 56% 42% 56% 50% 50% 58% 75%
Low power costs 56% 46% 70% 71% 59% 92% 85% 65% 58% 69% 25%
Absence of organized market for DERs 61% 54% 59% 57% 13% 23% 24% 35% 46% 55% 50%
Cost of development/ deployment 50% 46% 68% 29% 59% 77% 67% 88% 85% 89% 50%
Lack of well-defined M&V framework 46% 18% 35% 14% 33% 27% 14% 50% 27% 41% 25%
Organizational/Operational
Competition for human/financial resources 63% 46% 58% 17% 43% 46% 39% 43% 36% 36% 25%
Lack of staff knowledge and capability 44% 50% 30% 43% 47% 50% 19% 47% 58% 23% 0%
Lack of standardized technical specs/agreements 35% 39% 48% 40% 20% 15% 29% 33% 25% 38% 0%
Insufficient intra-organizational coordination/ communication 27% 50% 17% 29% 15% 40% 25% 23% 33% 22% 67%
Infrastructure/Technology
Data issues (e.g. lack of AMI, poor “big data” tools) 54% 39% 38% 60% 30% 25% 17% 50% 25% 30% 67%
Back office systems 50% 60% 52% 0% 46% 30% 39% 46% 70% 38% 25%
Communication protocols not standard; interoperability issues 36% 50% 48% 0% 18% 18% 17% 27% 46% 30% 25%
Difficulty integrating DERs with current infrastructure 24% 23% 54% 20% 33% 31% 19% 47% 23% 36% 0%
Concerns about cybersecurity 15% 20% 48% 14% 8% 20% 32% 8% 10% 33% 0%
Lack of test facilities & infrastructure for communications to distributed devices 23% 27% 30% 0% 23% 18% 22% 31% 55% 18% 0%
Ability to control/ manage EV charging and discharging 25% 33% 30% 20% 13% 11% 16% 14% 40% 30% 0%
Unstable vendor supply chain 39% 25% 29% 20% 18% 17% 21% 46% 36% 39% 0%
Legal/Regulatory
Lack of established tariffs & contracts for DER 33% 63% 50% 60% 21% 44% 32% 39% 75% 35% 75%
Concerns about data privacy 31% 27% 54% 14% 8% 9% 24% 8% 10% 29% 0%
Environmental regulation/compliance and permitting/siting issues 0% 0% 24% 33% 42% 18% 0%
Source: Cadmus DER barriers rating survey Percent of respondents rating the barrier as a 4 or 5 on a 1 to 5 significance rating scale SME=BPA subject matter expert; STK=external stakeholder; PC= BPA power customer; DSP=DER service provider Note: Sample sizes identified are maximum sample size for each interview group and DER category. Due to small sample sizes, results should be interpreted as directional
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