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www.peakload.org
Justin Chamberlain, CPS EnergyPoornima Eber, National Grid
Olivia Patterson, Opinion DynamicsTamer Rousan, Ameren
Connected DevicesInterest Group
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Agenda• How BGE Manages Connected Devices through Operability & Offline
Processes• Combined Session: Connected Devices and a Future DSO
• Connected Devices at Arizona Public Service• DER as NWA – Evaluation and Implementation Considerations
• Solve Your EV Questions Panel
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How BGE Manages Connected Devices through
Inspections & Offline Process
Carley Czyzewski & Dana DeRemigisBaltimore Gas & Electric (BGE)
Senior Energy Efficiency Program Managers
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Device Inspections: One-Way A/C Switches
Offline Process: Smart Thermostats
How BGE Manages Direct Load Control Devices to Reduce Performance Risks
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Connected Devices: Outline• BGEs Inspection Process for
Switches, Carley Czyzewski• Overview of the Program• File Preparations • Data Analysis• Non-Operational Device List• Marketing and Vendor
Involvement• Work Order Codes• Outcomes
• BGEs Offline Process for Smart Thermostats, Dana DeRemigis
• The Issues• The Numbers• The Goals• The Process• The Resolution• The Statistics and Timeline• The Next Steps
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Overview of BGE’s DLC Program• Started in the late 1980’s• The current program version was developed in 2008
• Supports EmPOWER MD, Public Service Commission Surcharge• Offer customers bill credits over the summer season in return for cycling their
A/C compressors during periods of peak demand• Approximately 350,000 active devices installed
• BGE owns, installs and manages these devices• Types of A/C Devices
• 163,000 Switches• 157,000 UPro thermostat• 32,000 Wi-Fi thermostats
• As of 2016, BGE is fully deployed with AMI meters• Approximately 314 MW of peak reduction• Energy Savings Days consist of PeakRewards and Smart Energy Rewards
(behavioral) programs
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Managing Devices• Why does BGE conduct Switch Inspections & Offline
Process?• Reduce utility performance risks• PJM charges a non-performance fee for any shortfall of committed
resources• Accurate MW reduction reporting and meeting PJM commitments• Improve cost-benefit of the program, overpaying bill credits• Overall reliability of DLC program, company owned assets
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• Load Forecasting & Demand Response Market Operations
• Use panel regression to determine operability rate using AMI data and Operability study results
• BGE performs A/C switch inspections to keep our Operability rate accurate
• A/C switches were selected since an appointment is not needed • 72% of the switches are ≥ 9 years old
• AMI data is used to help determine which one-way devices are not operating as expected
• This list is shared with the field inspectors for in the field testing
• Smart thermostats are tracked weekly and monthly for an offline rate
Data Analysis for A/C Switch InspectionsYear Operability Rate
(Regression & Field Inspections)
2015 86.0%
2016 88.0%
2017 85.1%
2018 86.1%
2019 82.9%
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Data Analysis for A/C Switch Inspections• Develop a list of switches that have a high
probability of not working• From list of PeakRewards customers, keep only switches with
cycling above 0%• Remove anyone that overrode during the events• Remove net meter and keep only active accounts with Smart
Energy Rewards (behavioral)• Determine date/time of analysis • Evaluate weather conditions of event days• For each event day, read in hourly data and merge data points
Date Program Activity AC Cycling % Start Time End Time Length
July 17, 2019 SER PR-AC 50% 1:02 PM 6:00 PM 4 Hrs 58 Min25% 6:01 PM 6:30 PM 0 Hrs 29 Min
RandomOut 0% 6:30 PM 7:00 PM 0 Hrs 30 Min
July 19, 2019 SER PR-AC 50% 1:01 PM 6:01 PM 5 Hrs 0 Min25% 6:01 PM 6:30 PM 0 Hrs 29 Min
RandomOut 0% 6:30 PM 7:00 PM 0 Hrs 30 Min
Hour 17-Jul 19-Jul 17-Jul 19-Jul
10 87 89 79.9 80.711 91 91 81.6 81.712 94 92 82.7 82.513 95 93 82.8 83.014 97 94 83.4 83.715 95 95 83.5 83.816 96 97 83.9 84.517 96 96 83.9 83.818 92 95 82.1 83.619 75 95 75.25 83.320 76 92 75.25 82.021 76 90 74.96 80.6
Mean 92 95 82.0 83.8Min 75 94 75.3 83.3Max 97 97 83.9 84.5CV 9.2% 1.1% 4.1% 0.5%
DryBulb WTHI
Hours 2 pm to 7 pm
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• Evaluate data to develop a list of potential non-operational devices:
• Identify customers that appear to have their A/C off by reviewing the variation in whole house usage over the hour before the event, hours of event, and the hour after the event
• Identify customers that appear to have their air conditioners on and responding to the event
• The remaining customers are placed in the uncertain category• Keep only active device/premises• Determine if the customer had a new HVAC installed under
the rebate program
Data Analysis for A/C Switch Inspections
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After gathering the data, what’s next?• Customer Outreach Direct Mailer
1. Initial Notice – Informs the customer a technician will be on their property to inspect their a/c switch within the next 30-60 days
2. Follow up Notice – Informs the customer a technician attempted to inspect their a/c switch, but was unable to access it
3. Final Notice – Informs the customer that they need to contact BGE to schedule an appointment for an inspection within the next 30 days or they will be removed from the program
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• Field Personnel Inspections• Two field technicians are assigned to work switch inspections using
the uncertain list• Field Scout, hardware paging tool• Save results into system of record
After gathering the data, what’s next?
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After field inspections, what’s next?
WO Code Results Definition
Pass 48% No issues found
Failed Tampered
24% Device mounted, wiring removed, by-passed, cut, preventing load reduction
Failed New HVAC
40% HVAC/device no longer connected, device removed, left hanging or thrown away, no evidence of conduit entry points
• Work Order Results (2018)• Program Terms &
Conditions include inspection at anytime as device is owned by BGE
• Total number of A/C switches inspected 1,420
• 678 Passed• 742 Failed
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Device Inspections: One-Way A/C Switches
Offline Process: Smart Thermostats
How BGE Manages Direct Load Control Devices to Reduce Performance Risks
www.peakload.org
Connected Devices: Outline• BGEs Inspection Process for Switches,
Carley Czyzewski• Overview of the Program• File Preparations • Data Analysis• Non-Operational Device List• Marketing and Vendor
Involvement• Work Order Codes• Outcomes• Financial Impacts
• BGEs Offline Process for Smart Thermostats, Dana DeRemigis
• The Issues • The Numbers• The Goals• The Process• The Resolution• The Statistics and Timeline• The Next Steps
www.peakload.org
Managing Smart Thermostats• The Issues:
• Company owned assets (smart thermostats) installed and enrolled• Not registered or offline for an extended timeframe• Reliability of the DLC program • Accurate MW reduction reporting and PJM commitments• Cost of paying annual customer bill credits (per device)
• $50-$100• $75-$150• $100-$200
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Managing Smart Thermostats• The Numbers:
• Launched Smart Thermostat program, launched Summer 2017• June 2018 = 15,800• June 2019 = 29,600• October 2019 = 33,300
• Program Terms & Conditions at Enrollment • Must be registered and connected to home Wi-Fi
• Cycling choice and summer bill credits• 50% = $50 per summer• 75% = $75 per summer• 100% = $100 per summer
• New enrollment, first time A/C device receives double• First year bonus up to $100
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Managing Smart Thermostats• The Goal:
• Minimize the offline rate• More accurate MW reduction estimates• Lower program costs, paying for devices not online• Maintain customer satisfaction in overall program• Better reliability and operational devices• Industry accepted standard is 8-13% offline rate• BGE goal is < 5% offline rate
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Managing Smart Thermostats• The Process: Manual started June 2018 ran monthly, time consuming
1. Reviewed/Revised the Terms & Conditions2. Data points required from manufacturer’s API and Utility Dashboard
• Serial Number• Last Connected Data (Last Day the Wi-Fi was successfully connected)• Registered (True/False)
3. BGE matches the S/N with its Customer Care & Billing system (CC&B)4. Excel spreadsheet with V-Look Up formulas5. Filter data by number of days offline (not connected)
• Week 2 (W2) = 7-14 consecutive days = Email or Letter 1• Week 4 (W4) = 21-28 days = Letter 2• Week 6/Remove (W6/RMV) > 36 days = Outbound Call or Email from
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Managing Smart Thermostats• The Resolution: Moving from Manual to Automated Process
• Interim Week 6 Actions• Long Term offline from 36 days to over 600 days• Outbound Calls from the PeakRewards Call Center (PRCC)
• 120+ days offline included over 600 customers• 200+ days offline included over 300 customers
• Top Three Reasons customers went offline1. Thermostat replaced directly by manufacturer, S/N was not in BGE inventory2. Customer just wanted to get the free tstat, and did not want the credits3. Customer did not understand the benefits of Wi-Fi, weather, app control, etc.
• Email and Letters revised to address the call center findings• Developed process improvements with manufacturer
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Managing Smart Thermostats• The Process: Automated started June 2019 runs weekly
• Worked as IT enhancement project (Roadmap 2019)1. Dec 2018 – Jan 2019, planning and requirements gathering 2. Feb, planned reporting needs and test scripts written by IT3. Mar/Apr, fully tested4. Business team, managed emails and letters leading up to the bulk
removal in May 20195. Automated offline process, went live in June
• Weekly Reporting (Status and Enrollment)• Customer Contact saved to CC&B at each step • Letter Data (.LTR) files posted to SFTP for Email and Print Vendors• Ongoing Quality Assurance and eProof approval in process
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Managing Smart Thermostats• The Statistics & Timeline:
• 51% of Offline customers take positive action from the emails and letters
• Average of 74% of Offline customers remain in the program (month/month)
• Dollars Saved = total bill credits Not paid for offline devices
Manual Jun-18 Sep-18 Dec-18 Mar-19 May-19 Jun-19Off line Rate 7.4% 6.2% 6.5% 7.7% 4.5% 4.2%Installed Devices 15,800 21,100 25,100 28,300 29,300 28,900
Off line Devices 1,165 1,315 1,625 2,180 1,320 1,200 Emails/Letter 1 85 950 170 130 650 Letter 2 700 1200 75 340 Removal Letter 710 690Dollars Saved 53,250$ 51,750$
AutomatedJul-19 Aug-19 Sep-19 Oct-19
Total Average
Off line Rate 3.6% 3.5% 3.3% 3.2% 3.4% Since July
Installed Devices 30,300 31,600 32,400 33,300 33,300 As of Oct 31
Off line Devices 1,100 1,095 1,075 1,080 1,088 Per Month
Emails/Letter 1 530 695 615 490 583 Per Month
Letter 2 300 330 325 215 293 Per Month
Removal Letter 300 315 295 220 283 Per Month
Dollars Saved 22,500$ 23,625$ 22,125$ 16,500$ 189,750$ Total
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Managing Smart Thermostats• The Next Steps:
• Continue to monitor for outliers• Refine reporting as needed• Ongoing quality assurance standards• Continue weekly cadence• Roadmap 2020, IT Project to include Move-out Move-in rule
• MOMI stay enrolled until after 36 additional days offline • Based on pending stop/start and service start date
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Possible Qs from Audience:1. How do you ensure that Customers Register their Wi-Fi Device on time? Answer:
Part of the installation service checklist and required before leaving the home. Held to this standard by quality and customer surveys.
2. How do you handle Issues caused due to CCB failing to update Un-Enroll Transaction after W6. Answer: We create a Service Request to our DR vendor to fix the issue with a SLA of 3 days or less.
3. What is the effectiveness % of Customers who take positive action on receiving the W2, W4 Emails/Letters? Answer: We are still determining the true numbers through reporting, based on the significant drop from W2 letter to the W6 removal, our estimate is that 51% of offline customers reconnect to Wi-Fi and remain in the program because of our offline process. Overall average is 74% of customers offline stay in the program
4. After the customer has been removed by offline process, can they re-enroll? Answer: Yes, they call the call center to confirm connection to Wi-Fi, CSRs have an action in Yukon platform that can “ping” the online status of the S/N. CSRs can also ask that customer sends an email with the screen shot of their S/N and status from smart phone app.
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Combined Session: Connected Devices and a Future DSO
Moderators: Justin Chamberlain & Olivia Patterson
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PresentersConnected Devices
Tom Hines, APS
Judson Tillinghurst, APS
Renee Guillory, APS
DER as NWA – Evaluation and Implementation Considerations
Ralph Masiello, Quanta Technology
Farnaz Farzan, Quanta Technology
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Arizona Public Service2019 PLMA: Connected Devices
Renée GuilloryTom Hines
Judson Tillinghast
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APS Overview• Company
• Serving AZ since 1886• Largest taxpayer in the state• $3.4B annual economic impact
• Customers• 1.2 million (89% residential)
• Peak Demand• 7,367 MW (2017)
• Generation Capacity• About 6,200 MW of owned or leased capacity (~8,600
MW with long term contracts)• Including 29.1% interest in Palo Verde
Generation Station, the nation’s largest carbon-free generation facility
• Transmission & Distribution• 6,186 miles of transmission lines• 11,167 miles of overhead lines and approximately
21,524 miles of underground primary cable
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Arizona Resource Needs are Changing• Seasonal variation of resource needs
• Continued evening growth during high load, summer periods• Continued reduction in net load during the daytime, non-summer periods
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Solar Overproduction• Renewable resources economically curtailed
to ensure grid stability
• Approximate renewable curtailment in CAISO• 2017: 380,000 MWH• 2018: 461,000 MWH• 2019 YTD May: 630,864 MWH
• Solutions to solar overproduction• Energy Imbalance Market• Storage• Solar + Storage• Demand response• TOU rates• Customer involvement
CAISO Wind and Solar Curtailment by Month
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APS is Taking Leaps Forward Towards a Clean Energy Future1. Modern Rates2. Distributed Solar3. Rewards Programs
• Storage Rewards• Reserve Rewards• Cool Rewards
Modern Rates
Rewards Programs
Distributed Solar
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Modern Rates Benefit Customers
• Customer value for use that aligns to low-cost time periods of service
• Integration of otherwise curtailed renewable energy• Encourage customers shifting demand• Smarter use of energy to integrate more renewables• Increased opportunities in DER and DR• Opportunity to reduce carbon emissions
Modern Rates Create
•On-Peak•Off-Peak•Super Off-Peak •Demand
Modern Rates Components
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Customers are Responding to Modern RatesResidential Summer Load Profiles
• Average residential load shape for five similar Aug. & Sept. days
• Customers shifting energy from peak to 10-3 time frame
• Peak reduction• Integration of more clean
energy to grid
Observations
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Distributed Solar in APS Territory• Distributed solar added by year
• 2017: 151 MW• 2018: 132 MW• 2019: 120 MW Forecasted
Average System Size9 kWdc
Total Systems100,000+
Total Capacity1,100+ MWdc
#2 Utility in residential solar installed per customer (SDG&E #1)
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Rewards ProgramsManaged DER programs have value for customers and the distribution system:
• Demand Response (Peak Reduction)• Load Shift
• Peak demand reduction• Solar sponge
• Feeder congestion relief• Voltage support• Bill savings through modern rates• Enrollment rewards for customers • Annual participation awards for the
Cool Rewards DR program
Storage Rewards Batteries
Reserve RewardsWater Heaters
Cool Rewards Thermostats
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Storage Rewards Program• Program
• ~40 APS-owned and -operated batteries• Customer and utility share capacity
• System Benefits• Help customers shift energy usage and
manage peak demand • System peak reduction and other grid
operational benefits• Time of battery charging is modifiable
throughout year
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Reserve Rewards Program• Program
• 230 water heaters (thermal energy storage)• Customer-owned water heaters operated by APS• Shift usage into solar production period while
maintaining customer hot water
• System Benefits• Reduce system peak• Load management for solar sponging• Installed on targeted feeders
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Cool Rewards Program• Program
• Thermostat demand response• ~17,000 smart thermostats • Up to 20 call events during the summer months• Customers receive annual participation award• Participating customers can override events
without penalties
• System Benefits• Demand response load reductions during
system peak events• Pre-cooling shifts load into hours of high solar
production
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Cool Rewards – DR Event Variables to Consider• ‘No harm’ to customers on TOU/Demand Rates (3-8pm Weekday On-Peak)
• Affected protocols for when we could call events• Weekday event periods ran until 8pm to avoid causing rate impacts
• Event Variables Included:• Weekday vs. weekend event protocols• Pre-cool period vs. no pre-cool period• Standard events vs ‘Firm Load Dispatch’ events• Temperature offset of 2 vs. 3 degrees• Type of thermostat controlled (Nest vs. other brands)
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Biggest Cool Rewards Event to Date: Sunday August 4th
20 MW &30.8 MWH
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Connected Devices:
Gimme Shelter orGimme More, More, More?
Storage Rewards
Reserve Rewards
Solar Communities
Cool Rewards
EVs
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DER as NWA
Evaluation and Implementation ConsiderationsQuanta Technology
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Policy Pushes for DER and Value to the Grid• Several States are Pursuing Formal Approaches
to Valuing Distributed Energy Resources (DER)• The same concept is the starting point for all
such• Attempt to identify all the values that DER can
bring• Energy cost savings.• Emissions reduction and other environmental
benefits.• Local customer level reliability / resiliency.• Avoided T&D capital and operating costs.• The avoided T&D costs are the “Value to the Grid”
and a focus of much attention.Mandate InitiativeInvestigation
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• Methodology through which value of DER is calculated
Methodology
• Implementing value of DER for a large volume of projects (e.g., transparency and data sharing, performance compliance for DER)
Implementation
• Utility’s incentives and earnings opportunities for administering and fostering the value of DER process
Incentives
DER Valuation
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What to value?
Value to Distribution Grid
• Several categories of value are potentially realized from DER.
• Some value streams are associated with value to the distribution grid.
• Distribution grid value streams are much more dependent on DER location, type and time.
Consumer
• Total Energy Costs• Demand Changes• Consumer Green Lifestyle• Consumer Backup Generation
Distribution System
• Distribution Capacity• Voltage• Reliability
Transmission System • Transmission Capacity
Wholesale Energy
Markets
• Losses • Congestion Costs• Generation Energy• Ancillary Services• Resource Adequacy• RPS Procurement
Society• Societal Avoided Costs• Public Safety Avoided Costs
Environmental
• Emissions• Waste Products• Water Pollution• Siting
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Principles of DER Valuation Methodology
Efficiency: Where DERs can provide a value to the distribution grid they should be compensated for doing so:• Deferring large investments to
accommodate for changes in load or to increase renewable hosting, or to improve local reliability
Accuracy: DER should be compensated for services they provide to the distribution grid• Address different
characteristics/capabilities of different DER Technologies
• Address differences in locational and temporal value of DER
Equity and fairness: Limit impact to non-participating customers and avoid over-compensation and distorted market signals• Avoid double counting when
some sources of DER value are compensated elsewhere
• Non-participating customers should not be harmed in terms of cost or grid performance
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Spectrum of Approaches
DER is compensated by type, by circuit voltage level and by region
DER compensated based on distribution grid needs at a given
location and time
DER is planned/engineered to mitigate specific grid issues and can be compared to traditional
grid alternatives
More Generalized More Granular
The primary tradeoff when moving along the spectrum is accuracy, standardized compensation and ease of administration
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Value is Locational
56
SubstationCircuit segment
expected to see an overload
Upstream DER: Provides no value to mitigate projected overload.
Downstream DER: May be able mitigate projected overload depending
on the DER type (i.e. generation pattern).
Potential valueNo value DERDER
DERDER
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Methodology for DER Valuation
Develop forecast
Identify binding constraints
Traditional project to address constraints
Allocated Cost of Capacity (ACC)
Locational Marginal Value
(LMV)
Marginal cost of grid upgrades required to
mitigate overloads and voltage violations in
the network
Sum of the marginal value of real power, reactive
power and reserve provided by the DER at
any point in time
Traditional distribution planning stops here.
57
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Value is LocationalIndicates over-loaded sections
• Three regions of non-zero LMV can be formed where:
• LMV1 < LMV2 < LMV3
• Variation within each cluster is due to losses
• Difference between clusters depend on the amount of over-load on upstream sections
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Numerical Example
• IEEE 33-bus examples• Amp overload
• Branch 2-22 downstream of 1 overload• Branch 2-25 downstream of 2 overloads• Branch 2-18, 2-33 have buses that are
downstream of all 5 overloads
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Numerical Example• IEEE 33 bus examples• Undervoltage
• Low contribution of buses on 2-22 and 2-25 due to long distance
• First 5 buses of branch 2-33 can contribute to undervoltage buses
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Impact of LMV on DER FinancialsDeveloper’s perspective:• Pre-tax Project NPV
• Pre-tax Equity NPV• Pre-tax Project NPV = NPV [Market benefit + LMV payment (reliability service revenue) – OpEx – CapEx]• Pre-tax Equity NPV = NPV [Market benefit + LMV payment (reliability service revenue) – (1-debt ratio)*CapEx –
interest – Debt principal payment]
-3
-2
-1
0
1
2
0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 44 46 48 50 52 54 56 58 60 62 64
Cum
mul
ativ
e CF
($M
)
Quarters
Pre-tax Project Cummulative Cash Flow (Quarterly)
WO LMV / W market benefit W LMV / W market benefit (Option 3)
LMV reduces the break-even year (from
13 years to 8 years)
Grid Service Thermal Overload
Traditional Cost $1M
DER Technology Battery Storage
DER Size 1 MW/ 3.25 MWh
DER EPC Cost 180 $/kW & 350 $/kWh
Replacement 12 Years
Traditional Cost $1M
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Impact of LMV on Developer Financial• Developer perspective:
• Pre-tax Project NPV• Pre-tax Equity NPV
• Pre-tax Project NPV = NPV [Market benefit + LMV payment (reliability service revenue) – OpEx – CapEx]
• Pre-tax Equity NPV = NPV [Market benefit + LMV payment (reliability service revenue) – (1-debt ratio)*CapEx – interest –Debt principal payment]
• Example: Thermal overload case• DER technology: Battery Energy Storage
• Size: 1MW/ 3.25 MWh
• ESS EPC Cost: 180 $/kW & 350 $/kWh
62
• Traditional Solution Cost: 1 $M• Battery replacement after 12 years
-3
-2
-1
0
1
2
0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 44 46 48 50 52 54 56 58 60 62 64
Cum
mul
ativ
e CF
($M
)
Quarters
Pre-tax Project Cummulative Cash Flow (Quarterly)
WO LMV / W market benefit W LMV / W market benefit (Option 3)
LMV reduces the break-even year (from
13 years to 8 years)
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Compensation Structure & Procurement
• Fair:• Charges and credits to be
allocated to the right parties
• Accurate:• Compensates right resource
for the right service at the right time and location
• Efficient:• Encourages and guarantees
participation of right resources for needed services
63
“Philosophical” Questions:• Choice of Timeframe for Cost of
Capacity Allocation• Lumpiness of Distribution
Capacity Upgrade• Granularity of Payment with
respect to Time and Location• DER Deployment
Compensation Structure Elements:• Compensation Mechanism;
e.g., Tariff vs. Auction• Existing vs. New DER• Penalty for Non-Compliance
Guiding Principles Design Considerations
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Monitoring and Performance
64
DER performance evaluation is key in:• Payments for service(s) offered as well as
compliance determination.• Building up knowledge base for future projects.• Providing feedback for planning process,
compensation design and procurement.
Performance test before allowing the resource to offer certain services:• Test procedure• Acceptable test score
On-going performance evaluation for each service offering• Data measurements and reporting should
support this.
Monitoring Performance
• NWA planning/implementation should consider monitoring and performance requirements.
• More than validation of DER installation and capacity as part of interconnection process will be required.
• Dispatchable DER requires some degree of monitoring and control.
• Role of third party aggregators to increase practicality.
• Coordination with ISO/RTO if necessary.
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Revenue Margin• Multiple communications alternatives considered: MPLS, 4G LTE, Secure VPN, Secure Gateway
• More expensive communication alternatives disadvantage smaller resources• Leveraging existing internet connections and equipment may be the only cost effective solution for smaller
resources
• Less expensive options exist but trade-offs should be understood and evaluated• Security, granularity requirements, etc
• Level of security requirements should be reviewed depending on resource size and market criticality
Scenario Name T1/MPLS 4G LTE Secure VPN Secure Gateway8 KW Residential-Revenue meter -1323.15% 8.10% 56.60% 23.42%8 KW Residential-Embedded meter -1310.38% 20.87% 69.37% 36.18%20 KW Small Business-Revenue meter -469.26% 63.24% 82.64% 69.37%20 KW Small Business-Embedded meter -464.15% 68.35% 87.75% 74.47%250 KW Parking garage/no internet-revenue meter 54.46% 97.06% 92.48% 91.42%250 KW Parking garage/no internet-embedded meter 54.87% 97.47% 92.89% 91.83%250 KW Parking garage/internet-revenue meter 54.46% 97.06% 98.61% 97.55%250 KW Parking garage/internet-embedded meter 54.87% 97.47% 99.02% 97.96%500 KW Big Box-Revenue meter 77.23% 98.53% 99.31% 98.77%500 KW Big Box-Embedded meter 77.43% 98.73% 99.51% 98.98%
1
2
3A
3B
4
Revenue Margin* Percentage Comparison-Redundant Configurations
*Net revenue margin compared to Locational-Based Marginal Pricing and expected revenue based on resource size
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Settlement & Compliance
66
• Failure to perform when called on has to result in penalties:
– Financial penalty– Claw back of incentives– Exclusion from future
payments/operations until the underlying performance problems are rectified.
• It is important for contractual agreements to be specific about responsibilities under different circumstances.
• Formal procedures for dispute resolution should be established.
Settlements Penalties
• Arrangements with aggregators/integrators vs. individual resources.
• Pay for performance mechanisms to encourage/compensate desired performance.
• Capacity performance mechanisms to incentivize resources that overperform.
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Culture Change NeededTransparency
Trust
Accountability
Review
Independent Determination
Forecasts and Planned Costs are Estimates
Only
Responsible for Forecast Errors
and Cost Overruns
Performance Base Rates
Methodology Assumptions Forecasts Plans NWA Decisions
Outcomes Only
Assumptions & Forecasts
Grid Needs & Planned Projects
Planning & Customer Data
Cost to Beat
Utilities and Regulators Operate on This Arc Today
per RMI
The RMI Playbook Moves to This Arc
Opaqueness
Distrust
No Accountability
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PanelistsEric Mallia, FleetCarma
Chris Ashley, EnergyHub
Daniel Carr, Alectra Utilities
Wayne Callendar, CPS Energy
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Closing Notes• Evaluation Forms
• Interesting Future Topics?• Feedback
• Third Member of the Connected Devices Team
• THANK YOU!
