Download Presentation - The California IDER and DRP Working Groups

Locational Net Benefit Analysis
Working Group
July 26, 2016
OAKSTOP, Oakland, CA
drpwg.org
1
Agenda
Time
Topic
9:00-9:15
9:15–10:15
10:15-11:45
11:45-12:30
Introductions
Discussion of Stakeholder Comments
Use Case Discussion (Procurement)
Lunch
12:30 -12:45
12:45 –1:45
1:45-3:15
Distribution Grid Services
Methodology Discussion (E3)
Data and Maps
3:15 – 3:30
Summary & Next Steps
2
LNBA Working Group Background
LNBA WG Purpose- Pursuant to the May 2, 2016, Assigned Commissioner’s
Ruling (ACR) in DRP proceeding (R.14-08-013), the Joint Utilities are required to
convene the LNBA WG to:
1.
2.
3.
4.
Monitor and Support Demonstration Project B
Improve and refine LNBA methodology
Coordinate with IDER Cost Effectiveness WG on system-level valuation activities
Coordinate with IDER Competitive Solicitation Framework WG where objectives
overlap (e.g. description of grid deficiencies and performance requirements)
CPUC Energy Division role
•
•
•
Oversight to ensure balance and achievement of State objective
Coordination with both related CPUC activities and activities in other agencies (CEC,
CAISO)
Steward WG agreements into CPUC decisions when necessary
More Than Smart role
Engaged by Joint Utilities to facilitate both the ICA & LBNA working groups. This
leverages the previous work of MTS facilitating stakeholder discussions on ICA and
LBNA topics.
3
Draft LNBA Working Group Schedule to Date
May 2, 2016 - Assigned Commissioner Ruling on ICA and LNBA
May 12, 2016 – First Joint Utility meeting on ICA and LNBA
June 1, 2016 – First in person meeting to get input on Joint Utility
Implementation plans
June 9, 2016 – In person meeting to discuss LNBA Plans
June 16, 2016 –Utilities file LNBA implementation plans to CPUC
July 2016 – Q2, 2017 – Monthly LNBA WG meetings re/LNBA
implementation
Q4, 2016 – Final Demo B report due
Q4, 2016 – Long-term LNBA refinement intermediate status report due
Q2, 2017 – Utilities submit Long-term LNBA refinement final report due
4
LNBA WG Schedule - May 2nd CPUC ruling
Short Term: May 2nd – end of Q4 2016
• “Recommend a format for the LNBA maps to be consistent and readable to all
California stakeholders across the utilities’ service territories with similar data
and visual aspects”
• “Consult to the IOUs on further definition of grid service, and in coordination
with the IDER proceeding”
Long Term: May 2nd - end of Q2 2017
“Continue advancement and improvement of LNBA methodology, consulting to
IOUs on:
• Methods for evaluating location-specific benefits over a long-term horizon
that matches with the offer duration of the project
• Methods for valuing location-specific grid services provided by advanced
smart inverter capabilities
• Consideration/development of alternatives to the avoided cost method
(ex: distribution marginal cost method, etc.)
• IOUs shall determine a method for evaluating the effect on avoided cost of
DER working “in concert” in the same electrical footprint of a substation”
5
Proposed Schedule for LNBA WG topics
Element from Ruling
6.1.a Recommend a format for the LNBA maps to be consistent and
readable to all CA stakeholders across the utilities' service territories
with similar data and visual aspects (color, mapping tools, etc.)
6.1.b Consult to the IOUs on further definition of grid service, as
described in requirement (1)(B)(iv-v) of Section 4.3.1 above, and in
coordination with IDER proceeding
6.2.a. Methodology advancement and improvement: Methods for
evaluating location-specific benefits over a long term horizon that
matches with the offer duration of the DER project
6.2.b Methodology advancement and improvement: Methods for
evaluating location-specific grid services provided by advanced
smart inverter capabilities (see smart inverter functions ID'd by
Smart Inverter Working Group)
6.2.c Methodology advancement and improvement: Consideration
and development of alternatives to the avoided cost method, such
as distribution marginal cost or other methods
6.2.d Methodology advancement and improvement: IOUs shall
determine a method for evaluating the effect on avoided cost of DER
working "in concert" in the same electrical footprint of a substation
Date IOU
time frame (short completed/wi Date(s) WG
or long term)
ll complete will discuss
short term
SeptemberDecember
October
short term
August
long term
August
long term
September
long term
July
long term
December
6
Discussion of
Stakeholder Comments
7
Stakeholder Comments
DPA Selection:
Unlike PG&E and SDG&E, SCE proposes to conduct Demo B in a different
DPA than the one used for Demo C (LNBA Validation). What is the
rationale for this approach? Creation of the LNBA methodology and
validation of the methodology should be conducted in the same DPA.
8
Stakeholder Comments
Methodology:
E3’s description of its proposed methodology for calculating locational
deferral value is difficult to understand, seems unnecessarily complex, and
appears biased against DER. Additional discussion requested to better
understand the proposed approach and how it integrates with the IOUs’
proposed approach to the LNBA.
9
Stakeholder Comments
Methodology:
The proposed LNBA approaches will result in values for locational avoided
costs, not locational net benefits. To calculate net benefits, the IOUs must
include the costs to procure and integrate/interconnect the DER in the
calculations. The IOUs have indicated that they do no intend to include the
costs of the DER in Demo B.
10
Stakeholder Comments
Other:
How do the IOUs envision utilizing the LNBA results to support future DER
deployment? How will the IOUs integrate the LNBA results with current
and future DER procurement processes?
11
Definition of Net
For Discussion Only
12
Typical Net Benefit Analysis
Total Net Benefits = NPV (Benefits) – NPV(Costs)
This is not how the 5/2 ACR defines LNBA for Demo B
For Discussion Only
13
ACR Definition of LNBA for Demo B
Locational Net Benefit Analysis
• Is the sum of many
components
• DER cost is not one of the
components, but can be
determined through a
competitive solicitation
• Each component can be
positive or negative
• LNBA components which
exist over multiple years are
expressed as a net present
value
For Discussion Only
14
ACR Definition of LNBA for Demo B
Example of a negative avoided
cost in LNBA:
(+)
Energy storage device which is
used to reduce feeder peak load
may have a negative energy
avoided cost:
• The device has losses
• Feeder peak can occur when
CAISO prices are low
(-)
• Charge during high electricity
prices
• Discharge during low
electricity prices
For Discussion Only
15
ACR Definition of LNBA for Demo B
These are “net” sums of (+) and (-) values
NPV (yr1 Σ(+, +, -), yr2 Σ(+, +, -), yr3 Σ(+, +, -)… )
This is a “net” present value
For Discussion Only
16
LNBA Use Cases
For Discussion Only
17
LNBA Use Cases
Heat Map of Potential
Optimal Locations
Prioritization for DER
Deferral Opportunities
(Distribution Planning)
• Public/Indicative
• Confidential/Commercial
• Generic OR DER Specific
• Generic OR DER Specific
• No DER Costs Included
• DER Costs May Be
Included
• Visual heat map to inform
DER providers and
stakeholder of locations
where DERs may be most
valuable.
• Use LNBA to identify &
prioritize locations for
deploying DERs (results
may be shared with a
DPAG)
Future?
Demo B
For Discussion Only
18
LNBA and Competitive Solicitations
• LNBA as defined for Demo B
•
•
•
•
Does not include DER Costs
Uses public inputs (e.g. E3 energy price forecasts)
Produces indicative results
Can be DER technology-agnostic
• Competitive Solicitation Bid Evaluations
• Include DER Costs
• Use confidential inputs (e.g. IOU energy price forecasts,
DER provider offer prices)
• Produces commercial results
• Are specific to the technology in a DER offer
• Provides an open opportunity to build DER portfolios
For Discussion Only
19
LNBA and Competitive Solicitations
• LNBA is currently defined as a public analysis for
informational rather than commercial purposes
• Analogous to RPS Calculator and Energy Storage
Common Evaluation Protocol
• In competitive solicitation bid evaluations, IOUs
calculate same avoided cost components as LNBA
using proprietary and commercially sensitive
inputs
• Competitive solicitation bid evaluations are subject
to non-market-participant review in Procurement
Review Group (PRG)
For Discussion Only
20
LNBA Demo B
Methodology
Brian Horii
Energy and Environmental Economics, Inc.
July 22, 2016
Agenda
Background on DERAC/ACM and LNBA
Avoided cost theory
Example calculations
22
DERAC/ACM and LNBA
The Distributed Energy Resource Avoided Cost
(DERAC) calculator, and the Avoided Cost Model
(ACM).
• ACM is an update to DERAC
• Calculate system-wide hourly avoided costs for each IOU
• Energy and Emissions
• Generation Capacity
• Ancillary services
• Losses
• RPS adder
• Local T&D Capacity
LNBA will replace the hourly Local T&D Capacity
numbers with Demo B hourly values.
23
Avoided Cost Theory
LNBA will use the Real Economic Carrying Charge
(RECC).
• RECC used to calculate the annual economic value or
“economic depreciation” of an asset.
• Economic depreciation = value of deferring the asset and its
future replacements by one year, in constant real dollars.
Any change in O&M costs is also included.
• Economic value = Full Cost of Asset * RECC + DO&M
• Full Cost of Asset = Present Value of revenue requirements
associated with capital project
RECC =
(From EPRI Electric Utility Rate Design Study, How to Quantify Marginal Costs: Topic 4, 1977)
24
Calculation examples
Discrete Deferral Value for one year
• Deferral Value = Full Cost of Asset * RECC + DO&M
• RECC Calculation
• i = 2.5%, r = 7%,
book life = 40 yrs
•
𝑟−𝑖
1+𝑟
1+𝑟 𝑁
1+𝑟 𝑁 − 1+𝑖 𝑁
Item
Investment Cost
Variable
Low
TDCapital ($M)
$ 8.00
RECC
5.12%
RRScaler
150%
Incremental O&M DO&M ($M/yr)
$ 0.20
One year Deferral SavingsOne ($M) $ 0.81
• RECC = 4.5%/1.07 *1.07^40/(1.07^40 - 1.025^40) = 5.12%
• Full Cost = Direct Capital * RRScaler = $8M * 150% = $12M
• Deferral Value = $12M * 5.12% + $0.20M = $0.81M
25
Deferral Value for more than one
year
RECC-based deferral values escalate with inflation each
year.
Discounting the stream of annual deferral values yields
the total present value of a multi-year deferral.
• 𝑫𝒆𝒇𝒆𝒓𝒓𝒂𝒍 𝑻 =
𝟏+𝒊 𝒚−𝟏
𝑻
𝒚=𝟏 𝑺𝒂𝒗𝒊𝒏𝒈𝒔𝑶𝒏𝒆 𝟏+𝒓
• SavingsOne = Deferral value savings in the first year = $0.815M
• Two year deferral = $0.815M + $0.815M *(1.025/1.07) = $1.6M
26
Demo B may include a range of
cost values
Low, Medium, and High estimates for the same
project
Item
Investment Cost
Incremental O&M
One year Deferral
Two year Deferral
Variable
TDCapital ($M)
RECC
RRScaler
DO&M ($M/yr)
SavingsOne ($M)
SavingsTotal ($M)
Low
$ 8.00
5.124%
150%
$ 0.20
$ 0.815
$ 1.60
Med
$ 10.00
5.124%
150%
$ 0.30
$ 1.069
$ 2.09
$
$
$
$
High
15.00
5.124%
150%
0.40
1.553
3.04
27
Avoided Cost can be Expressed in
Multiple Ways
Prior examples showed the avoided cost as total
dollar savings.
Other methods are
• $/kW. Value normalized based on the amount of peak
reduction needed to attain the deferrals
• $/kW-yr. Value annulaized over multiple contract years
$/kW Avoided Cost for a Two Year Deferral
Value
Two year Deferral
MW Need (Hi, Med, Lo)
Discrete savings per kW
Variable
Low
Med
High
SavingsTotal ($M) $ 1.60 $ 2.09 $
3.04
MW Need (2 yr)
8
6
4
DiscreteperkW
$ 199 $ 349 $
760
28
Effect of Uncertainty in MW need
Uncertainty in the MW needed for deferral
increases the range of avoided cost results
• High MW need is applied to Low Value case
• Low MW need is matched to High Value case.
Value
Two year Deferral
MW Need (Hi, Med, Lo)
Discrete savings per kW
Variable
Low
Med
High
SavingsTotal ($M) $ 1.60 $ 2.09 $
3.04
MW Need (2 yr)
8
6
4
DiscreteperkW
$ 199 $ 349 $
760
29
Avoided Cost in $/kW-yr
$/kW-yr take prior values and annualize them over a set
period of years.
Useful for comparison to traditional DERAC/ACM T&D
capacity costs, or for use in commercial contracts.
Annualization could use either a nominal or real discount
rate.
• For comparison to DERAC/ACM, a real discount rate would be used.
• For commercial purposes, a real discount rate would be used if the
payment value were to increase annually with inflation. If the
payment were to be constant in nominal dollars, the nominal discount
rate should be used.
Example using a 10 yr contract period and nominal discount rate
Value
Discrete one yr value
Annualization
Avoided Cost
Variable
DiscreteperkW
Annualization
AvoidedCost
Low
$199
14.2%
$28.40
Med
$349
14.2%
$49.65
High
$760
14.2%
$108.23
30
Treatment of Project Layers
DER may be able to affect multiple projects.
The LNBA tool will total the value for all upstream
projects that DER could impact.
Note that the timing of the need for peak
reductions could vary for the upstream projects, so
a local resource may not be able to attain a full
sum of the individual avoided cost values.
Also note that it may be more difficult for an IOU to
achieve deferral of upstream projects because of
the often higher peak reductions needed for such
projects.
31
Peak Need Timing
LNBA Tool will also have the ability to allocate T&D
capacity costs to hours of the year.
Allocating the costs to hours allows for
probabilistic estimates of peak reductions from
DER.
The exact methods are still under discussion.
• Peak month/hour
• Threshold-based peak period
• Uniform weights vs proportional to load
The LNBA Tool will also include tools to reorder
days based on weather and chronology so that
data from unmatched years can be synchronized.
32
Threshold-based Allocation
Based on T&D loads
Identifies the peak period
as all hours where load is
above the threshold
Also known as PCAF
method
• For proportional weights
• For uniform weights
33
Distribution Services, Attributes and
Performance and Measurement
Requirements
Subteam 1a
Competitive Solicitations Framework Working Group Meeting
Integrated Distributed Energy Resources Proceeding
Mark Esguerra
Topics to Cover
• Integrated Distribution Planning Process
Framework
• Definition of Basic Distribution Services
• Distribution Service Attributes
• Performance Requirements
2
Integrated Distribution Planning Framework
Distribution Resources Plan (DRP)
2
1
Distribution
Assumptions,
Scenarios &
Scope
Develop forecasts,
assumptions and planning
scenarios.
•
•
•
Demand forecasts
DER forecasts
DER Growth Scenarios
3
Integrated Distributed Energy Resources
(IDER)
4
5
Distribution
Grid Needs
Evaluate
Options
Distribution Grid Needs
• Load Serving Capacity
Prioritize Grid Needs
Planning
Assessment
Distribution Grid Studies
•
Distribution Capacity
•
Voltage Support
Requirements
•
Protection
•
Safety and Reliability
•
DER Hosting Capacity
•
DER Aggregator
Requirements
•
Coordination with
Transmission Planning
Sourcing
Sourcing Process to
satisfy needs identified
in DRP
Investment
framework/technical
feasibility
Implement “Wires”
alternatives for locations
deemed infeasible for
DERs
2
3
1
4
5
1- Shingle Springs
2- Mendocino
3 - Point Arena
4 - Molino
5 - Old Kearney
Overall Substation Location Map
Implement
“Wires”
Solution
3
Definitions of Basic Distribution Services
Distribution Service
Definition
Distribution Capacity
Load modifying or supply services that DERs provide via
dispatch of power output (MW) or reduction in load
that is capable of reliably and consistently reducing net
loading on desired distribution infrastructure.
Voltage Support
Improved steady-state voltage to avoid voltage related
investment. Dynamic voltage management to keep
secondary and primary voltage within Rule 2 limits.
(Voltage control through real and/or
reactive power)
Reliability (Back-Tie)
Load modifying or supply service capable of improving
local distribution reliability and/or resiliency. Service
provides fast reconnection and availability of excess
reserves to reduce demand when restoring customers
during abnormal configurations.
Resiliency (Microgrid)
Load modifying or supply service capable of improving
local distribution reliability and/or resiliency. Service
provides fast reconnection and availability of excess
reserves to reduce demand when restoring customers
during abnormal configurations. Service also provides
power to islanded end use customers when central
power is not supplied and reduce duration of outages.
3
7
Distribution Service Attributes
• Locational Specificity of Distribution
Services
• Level or Magnitude of Required DER
Response
• Timing and Duration of DER Response
• DER Availability and Assurances
3
8
Performance Requirements
• System Availability
• Data Availability
• Response Time
• Quality of Response
3
9
APPENDIX
Distribution Grid Needs
3
Hypothetical examples of Distribution Service
Attributes
1
Assumptions,
Scenarios &
Scope
2
3
4
5
Distribution
Grid Needs
Evaluate
Options
Distribution
Portfolio
Distribution
Planning
Assessment
41
Distribution Capacity: Substation Transformer Overload
Distribution Grid Need
• An 11.88 MW rated substation
transformer is forecasted to overload in
the summer months.
• Substation transformer capacity deficiency
is determined to be:
‒ 1.4 MW by 2019
‒ 2.6 MW by 2020
‒ 3.6 MW by 2021
• Traditional “wires” solution is to replace
existing or install an additional
transformer, after exhausting available
capacity through field switching onto
adjacent distribution feeders.
42
Distribution Capacity: Substation Transformer Overload
Potential DER Solution for Overload Need:
• Attributes of DER performance must match overload issue attributes to
provide relief of capacity constraint
• Other attributes of DERs must address grid issues stemming from DERs
providing relief of capacity constraint (e.g. ramp rate)
DER Attributes to Procure
YEAR
2017
2018
2019
2020
2021
Distribution Capacity Need (MW)
-
-
1.4
2.6
3.6
Distribution Capacity Need (MVAr)
-
-
-
-
-
Months when needed
-
-
Aug-Sept
Aug-Sept
July-Sept
Days when needed
-
-
Mon-Fr
Mon-Fr
Mon-Fr
Time when needed
-
-
16:00-19:00
15:00-20:00
14:30-20:30
Duration (hours/day)
-
-
3
5
6
1
3
5
Frequency of Need (days/month)
43
Voltage Support Services: Steady State Under Voltage
Forecast Under Voltage Issue:
• A pump station customer is
planning to convert two
pumps from diesel to
electric by 2020
Rule 2 Limit
• The pumps will add an extra
1 MW to peak load
condition. Customer is
located close to the end of a
radial feeder
• Projected under voltage
conditions near the end of
the feeder is found to occur
around forecasted peak
loading times
M
Rule 2 Limit
44
Voltage Support Services: Steady State Under Voltage
Potential DER Solution for Overload Need:
• Attributes of DERs should match under voltage issue attributes to stay within Rule 2
voltage thresholds (±5% of nominal voltage)
• Attributes of under voltage issue
– Needed voltage changes (ΔV) to stay within Rule 2 limits
– Locations where under voltage occur
– Times and duration when under voltages occur
• Other attributes of DERs must address grid issues stemming from DERs providing
voltage support (e.g. ramp rate)
DER Attributes to Procure
Distribution Capacity Need (kW)
Distribution Capacity Need (kVAR)
Duration (hours/day)
Frequency of need (days/month)
Time Needed
Days Needed
Months Needed
Electrical Proximity from Voltage Issue
Ramp Rate (kW/min)
2017
-
2018
-
2019
-
-
-
-
-
-
-
-
-
-
YEAR
2020
500
50 at lagging PF
3
8
17:00-20:00
Mon-Fr
June-July
0.5 Circuit Miles of
SPID 77943XXXXX
N/A
2021
550
60 at lagging PF
3
8
17:00-20:00
Mon-Fr
May-July
0.5 Circuit Miles of
SPID 77943XXXXX
N/A
12
Voltage Support Services: Steady State Under Voltage
Location Matters:
G
M
•
Almost Identical Voltage
Profile when Compared to
no DER Scenario
•
Voltage is Back within
Rule 2 Limits
Rule 2 Limit
GM
Rule 2 Limit
13
Demo B Mapping
For Discussion Only
47
ACR Requirements
• “LNBA results shall be made available via heat map, as a
layer along with the ICA data in the online ICA map.” (pg. 32,
4.4.2(1))
• “The electric services at the project locations shall be
displayed in the same map formats as the ICA, or another
more suitable format as determined in consultation with the
working group.” (pg. 32, 4.4.2(1))
• “The DER growth scenario used in the distribution planning
process for each forecast range should be made available in
a heat map form as a layer in conjunction with the ICA layers
identified earlier.” (pg. 32, 4.4.2(2)a)
For Discussion Only
48
Demo B Map
• Use the same line segmentation as the ICA map
• Demo B map will display only deferrable projects
• Deferrable projects would be defined by work done in
the IDER proceeding Distribution Services Subteam
• Due to the selection of the primary analysis (Table
2, pg. 26-27), areas with no deferrable projects
would result in the same, system-wide avoided cost
• To show the impacts of the DER growth scenarios
coupled with LNBA results, each DER growth
scenario would be a user selectable layer on the
map
For Discussion Only
49
Demo B Map
LNBA Results [GR2-Near-Term]
Click here to
get addl. detail
LNBA Results [GR1-Mid-Term]
Growth Scenario 1
Set of Layers
LNBA Results [GR1-Long-Term]
DER Penetration [GR1]
Growth Scenario 2
Set of Layers
For Discussion Only
-Need a layer for
each DER?
-One layer with
sum of DER MW?
-One layer with
peak MW DER
impact?
-Need a layer for
3 time horizons?
50
Demo B Map – Discussion Topics
• The ACR requires the utilities to determine the
LNBA for the DER growth scenarios. As mentioned
in previous WG, these are not real projects at this
point.
• Is it more valuable to use the utilities’ base forecasts to
determine LNBA instead of one or both prescribed
growth scenarios?
• The ACR specifies three time frames: near term,
intermediate and longer term, should this be the
basis for displaying projects on the LNBA Map?
• If DER growth forecasts are to be displayed on heat
map, what level of granularity?
For Discussion Only
51
Summary & Next Steps
52
www.drpwg.org
53