Valuing demand response pub
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This document discusses valuing demand response programs at Consolidated Edison Co. of New York (ConEd). It outlines ConEd's existing demand response programs and describes the methodology used to value these programs, including using avoided costs, accounting for risk and timing factors. It also discusses a marginal cost study conducted to inform the valuation and outlines future regulatory developments around energy efficiency and distributed energy resources that could impact demand response valuation.
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Valuing demand response pub
- 1. Valuing Demand Response in Mesh Networks Lucas Finco June 5th, 2015 Energy Efficiency & Demand Management Department Consolidated Edison Co. of New York
- 2. Outline • Background • DR Valuation Methodology • Marginal Cost Study • Future Developments Background – Methodology – MC – Future
- 3. Outline • Background – ConEd’s DR programs • DR Valuation Methodology • Marginal Cost Study • Future Developments Background – Methodology – MC – Future
- 4. Background • DR programs @ ConEd – Contingency – Peak Shaving – Residential & Small Business Thermostat Controls – Room A/C controls Background – Methodology – MC – Future
- 5. Distribution Load Relief Program (DLRP) • 2 Hour Notification • Contingency program • Unpredictable ; no penalties • Operated across all of Con Edison territory • (NYC + Westchester) • Events can be called between 6:00 AM and midnight any day of the week • Customers required to reduce for a 4 hour period 5 Background – Methodology – MC – Future
- 6. Commercial System Relief Program (CSRP) • 21 Hour Notification • Peak shaving program • Heat driven and predictable • Penalties for non-performance • Operated across most of Con Edison territory • (NYC but in not in Westchester) • Called for a four hour fixed call window based on location. 11 AM - 3 PM 2 PM – 6 PM 4 PM - 8 PM 7 PM - 11 PM 6 Background – Methodology – MC – Future
- 7. Residential Demand Response Direct Load Control (DLC) Program Residential Central Air Conditioning Free Programmable Thermostat Eligibility: • Central A/C • Residence/Small Business Con Edison Benefit: • 40 MW of Callable Demand Response • 28,000 customers Customer Benefit: • FREE Smart Thermostat ($300 Installed) • $25 Incentive for Residential Customers or $50 Incentive for Small Business Customers • Control (Smartphone/Computer) • Energy Savings • Ability to Override Con Edison Control Background – Methodology – MC – Future
- 8. • modern electric outlet • Energy efficiency intelligence to wall outlets • Customers can save energy and manage use • Remote thermostat • With the modlet, smartens window air conditioners • Allows for participation in sponsored demand response events Background – Methodology – MC – Future
- 9. Outline • Background • DR Valuation Methodology • Marginal Cost Study • Future Developments Background – Methodology – MC – Future
- 10. DR Valuation Methodology • Avoided Cost • Granularity - Network Groupings • Risk • Timing / Overlap Background – Methodology – MC – Future
- 11. DR Valuation Methodology • Avoided Cost • Granularity - Network Groupings • Risk • Timing / Overlap Background – Methodology – MC – Future
- 12. DR Valuation Methodology Avoided Costs ($/kW-yr) Overlap & Coincidence Factors Enrollment (kW) Total Benefits ($/yr) Background – Methodology – MC – Future X X =
- 13. DR Valuation Methodology • Avoided Cost • Granularity - Network Groupings – Risk tier, excess capacity, night/day peak, network / radial • Risk • Timing / Overlap Background – Methodology – MC – Future
- 14. Animated illustration of network load changes over 24 hours of a peak day Background – Methodology – MC – Future
- 15. DR value model groups networks by timing, load shape, and high/low excess capacity23456 pctmw 0 3 6 9 12 15 18 21 24 hour Tier 2 - Evening peak 23456 pctmw 0 3 6 9 12 15 18 21 24 hour Tier 2 - Day peak 23456 pctmw 0 3 6 9 12 15 18 21 24 hour Tier 1 – Day peak - low excess 23456 pctmw 0 3 6 9 12 15 18 21 24 hour Tier 1 – Day peak - high excess 23456 pctmw 0 3 6 9 12 15 18 21 24 hour Tier 1 – Other - low excess 23456 pctmw 0 3 6 9 12 15 18 21 24 hour Tier 1 – Other - high excess 23456 pctmw 0 3 6 9 12 15 18 21 24 hour Radial - low excess 23456 pctmw 0 3 6 9 12 15 18 21 24 hour Radial - high excess Background – Methodology – MC – Future
- 16. DR Valuation Methodology • Avoided Cost • Granularity - Network Groupings • Risk – Peak Capacity Allocation Factor (PCAF) method • Timing / Overlap Background – Methodology – MC – Future
- 17. 17 Distribution Capacity Value Background – Methodology – MC – Future
- 18. DR Valuation Methodology • Avoided Cost • Granularity - Network Groupings • Risk • Timing / Overlap – Coincidence of DR events with risk – By vertical for generation, transmission and distribution – By network group for distribution – Also correct for ISO program overlap (both enrollment and event) Background – Methodology – MC – Future
- 19. Background – Methodology – MC – Future Peaking Risk Allocation Demand Reduction per Device (kW) Adjustment Interim Calculation Peaking Risk Allocation Demand Reduction per Device (kW) Adjustment Interim Calculation (A) (B) (A x B) (A) (B) (A x B) 0:00 0.0% 0.00 0.00 0% 0.00 0.00 1:00 0.0% 0.00 0.00 0.0% 0.00 0.00 2:00 0.0% 0.00 0.00 0.0% 0.00 0.00 3:00 0.0% 0.00 0.00 0.0% 0.00 0.00 4:00 0.0% 0.00 0.00 0.0% 0.00 0.00 5:00 0.0% 0.00 0.00 0.0% 0.00 0.00 6:00 0.0% 0.00 0.00 0.0% 0.00 0.00 7:00 0.0% 0.00 0.00 0.0% 0.00 0.00 8:00 0.2% 0.00 0.00 2.0% 0.00 0.00 9:00 1.0% 0.00 0.00 9.4% 0.00 0.00 10:00 2.3% 0.00 0.00 14.4% 0.00 0.00 11:00 3.8% 0.00 0.00 17.6% 0.00 0.00 12:00 4.9% 0.00 0.00 17.3% 0.76 0.13 13:00 6.0% 0.00 0.00 16.6% 0.94 0.16 14:00 7.3% 0.00 0.00 13.1% 0.98 0.13 15:00 8.2% 0.00 0.00 8.8% 1.06 0.09 16:00 9.4% 0.00 0.00 0.9% 1.15 0.01 17:00 10.8% 1.21 0.13 0.0% -0.21 0.00 18:00 10.2% 1.01 0.10 0.0% -0.06 0.00 19:00 11.8% 0.97 0.11 0.0% -0.02 0.00 20:00 14.5% 0.93 0.14 0.0% 0.00 0.00 21:00 7.5% 0.71 0.05 0.0% 0.01 0.00 22:00 1.8% -0.18 0.00 0.0% 0.00 0.00 23:00 0.1% -0.05 0.00 0.0% 0.00 0.00 Max Reduction (kW) 1.21 Max Reduction (kW) 1.15 Hour (start) Tier 1 - Day peaking, low excess capacityTier 2 - Evening Peaking
- 20. Output of the Model CECONY Cost-Benefit Model: DLC Residential - New Participants Total Resource Cost Test Utility Cost Test Societal Cost Test Ratepayer Impact Test Participant Cost Test All customers Benefits $5,789,229 $5,789,229 $5,789,229 $5,789,229 $344,987 Costs $3,464,911 $3,496,440 $3,464,911 $3,598,804 $94,588 Net Benefits $2,324,319 $2,292,789 $2,324,319 $2,190,425 $250,399 Benefit Cost Ratio 1.67 1.66 1.67 1.61 3.65 Benefits $0 $0 $0 $0 $0 Costs $0 $0 $0 $0 $0 Net Benefits $0 $0 $0 $0 $0 Benefit Cost Ratio New participants Benefits $5,789,229 $5,789,229 $5,789,229 $5,789,229 $344,987 Costs $3,464,911 $3,496,440 $3,464,911 $3,598,804 $94,588 Net Benefits $0 $2,292,789 $2,324,319 $2,190,425 $250,399 Benefit Cost Ratio 1.67 1.66 1.67 1.61 3.65 Existing active participants 0.00 0.50 1.00 1.50 2.00 2.50 3.00 3.50 4.00 Total Resource Cost Test Utility Cost Test Societal Cost Test Ratepayer Impact Test Participant Cost Test Benefit Cost Ratio 0.00 0.50 1.00 1.50 2.00 2.50 Tier 2 - Evening peak Tier 2 - Day peak Tier 1 – Day peak - low excess Tier 1 – Day peak - high excess Tier 1 – Other - low excess Tier 1 – Other - high excess Radial - low excess Radial - high excess Average New Enrollee Benefit Cost Ratio (TRC) by Network Group Background – Methodology – MC – Future
- 21. Outline • Background • DR Valuation Methodology • Marginal Cost Study • Future Developments Background – Methodology – MC – Future
- 22. Distribution vs Wholesale Con EdisonNYISOGen Background – Methodology – MC – Future
- 23. Marginal Cost Study • NERA performed marginal cost study specifically for EE & DM • Does not include many components of a typical cost of service study that cannot be reduced through EE or DM • Main Points – Collective vs. individual resources – Unit Costs – Excess Capacity – Sunk costs Background – Methodology – MC – Future
- 24. Outline • Background • DR Valuation Methodology • Marginal Cost Study • Future Developments Background – Methodology – MC – Future
- 25. Outcomes • New DR incentive structure approved by NYS PSC
- 26. Outcomes • New DR incentive structure approved by NYS PSC
- 27. Future Developments • Adaptation to EE, Storage, etc. • Future programs – BYOT – BYOD – Know your Circuits Background – Methodology – MC – Future
- 28. Future Regulatory Developments • Energy Efficiency Transition Implementation Plan (ETIP) – Integrating our programs by customer vertical – Requires integrated cost / benefit • Reforming the Energy Vision (REV) – BQDM Targeted Program – DERs – DSPP Background – Methodology – MC – Future
- 29. Questions • Contact me at fincol@coned.com • http://documents.dps.ny.gov/public/Common/ViewDoc.aspx ?DocRefId={BE9E7304-DA3C-4C06-B18B- ADD0D4568E3F}
- 30. Appendix
- 31. Current DLC Customers • Highest number of DLC customers in Westchester and Staten Island • Lowest number of customers in Manhattan • System need is high in Brooklyn 7 Each bubble is a distinct zip code - bubble diameter represents the number of current customers.
- 32. Valuing Demand Response through the FSC Model • Where is your need or at risk areas? • What characteristics of the need? • What should the incentive be? • Is it cost effective? 32
- 33. Efficient Frontier $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $0 $20 $40 $60 $80 $100 $120 $140 $160 $180 PerformancePayment($/kwh) Reservation Payment ($/kw) per Year Commercial DR Incentive Increase TRC = 1 Uniform Energy Reservation Current Tariff CURRENT TARIFF Reservation Performance DLRP - 1 $25 / $2 $1.00 DLRP - 2 $10 / $2 $1.00 CSRP - M $20 / $2 $1.00 CSRP - V $6.00
Editor's Notes
- Study performed and model built in conjunction consultant Josh Bode with Freeman Sullivan & Co. which is now Nexant. I will also discuss ConEdison’s Marginal Cost study originally performed by NERA consultants. Josh is in the audience today, and he and I will be available for questions.
- A quick outline of the topics I will cover in the talk.
- Day ahead program when forecasted load is above 96% of expected summer peak load.
- -$12 Million annual DLC budget approved by the Public Service Commission includes BYOT discussed later -35,000 Thermostats -Enrollment driven through marketing - Direct Mail and Email blasts -28,000 customers enrolled -40 MW of callable DR One time incentive payment $25 RSAP is annual Describe how technology works. NRTs -
- We have more pilot programs in the DR area that I will discuss near the end of the presentation Still a pilot NYC has high penetration of room A/C units, an estimated 6m units, mostly in older buildings, yet developers continue to install mini-splits and blower units with dial controls cooled from a central chiller. Annual incentive payment
- Why did we pursue the project? We pursued a new DR valuation model because we felt that we did not have a good valuation of DR in our service territory. We had been ordered to use a value of $100/kW-year for EEPS and $3/kW-month as the cost of avoiding rolling a mobile generator to provide load relief. We also wanted to get more granular about the value of DR. Does it have more value in different areas? At different times?
- FSC – Nexant 57 networks, 17 radial
- We use an avoided cost methodology, which means that we take future capacity investments that exist without the DR programs and calculate the savings from avoiding those investments. It is not as simple as just taking values from our marginal cost study. Certain aspects of the programs impact their value.
- Very High Level Overview - Start with costs per kW than can be avoided by reducing demand, multiply by overlap and coincidence factors, then by program enrollments to get total benefits of the programs. Costs are typically well known, and therefore the benefit/cost ratios can then be calculated.
- The level of granularity is important for this study. Should we calculate DR value as a system average? By network? By feeder? By transformer? Is more granular better? For instance, the cost of secondary cable for some of our networks is relatively stable, so there is no difference between many networks. Also, the number of projects available to evaluate a stable average becomes restrictive. What characteristics distinguish DR value in networks. Our answer was to group the networks by risk index, excess capacity, peaking times, and network/radial topology 57 networks, 17 radial
- FYI – this is the 24 hours of Thursday July 17, 2013 – the peak day load shape used by forecasting (they do not use “atypical” Fridays) - emphasis on day/night peaking, similarities Animation notes: Animation will start with a click (starts at hour ending 1am) Animation will proceed until HE 2pm where it will pause to show commercial peaks, click to continue click Animation will continue from 2pm to HE 5pm to show system peak time, click to continue click Animation will continue from 5pm to HE 9pm to show residential peaks in BQ, QN, BX, and upper MN, click to continue to end of animation - Above can be run in reverse (i.e. you can go back to previous point, by clicking back)
- 57 networks, 17 radial We are lucky to sit inside Electric Operations, within the engineering group, so we have access to corporate planners and designers. High Level: Need to account for that all networks and load areas are not the same. Need to put them in natural groupings, and arrived at 8 buckets. Groupings: Network/non-network, day/night and other (long peak), Tier 1 & 2 (based on NRI – commercial programs paid out this way w/ premium for Tier 2), and high/low excess distribution capacity. Tier 1 & 2 are based on outputs of the company’s NRI values – Network Risk Index – run by Distribution Engineering Detail: Excess capacity definition: For all networks we simulated n-2 conditions by removing the 2 largest feeders and dividing the network peak by this new capped capacity. For radial we looked at loading factor at substation level For all networks and radial areas the mean “loading factor” was 85%, which mean that on average networks have 15% excess capacity after accounting for n-2 conditions. All networks with a 15%+ capacity buffer in n-2 had high excess, and those less than 15% had low excess.
- FSC – Nexant Peak Capacity Allocation Factor (PCAF)
- FSC – Nexant Peak Capacity Allocation Factor (PCAF) This slide: Methodology to identify highest potential value hours for DR. Identify concentrations of value. Analyze by program by network group based on load distribution curves. Highest load hours of the year (top 100 hours per year averaged over 3 years) 2010-2012 Each entry represents the percent of total consumption above the base value (MW at the 300th highest load hour in the past 3 years) This example: CSRP – Tier 2 (Evening Peak). 9.7% of consumption in peak hours occurs in 8 PM hour in July. Next step not shown: This value is then matched with historical reduction data and avoided costs per kW-year (report calls this time-differentiating value) This metric summarizes how much additional peak load a DR resource can help support.
- Note the all of the cost tests are run and displayed at the same time. Cost tests are performed for all customers and existing customers & new participants separately. TRC test is also applied by network grouping.
- 22
- Such as service cable costs, customer meters, customer service, etc. Assets on a mesh network are collective and can be utilized by other customers if one reduces demand. This is not the case in radial networks, where only a few customers share secondary cables, secondary transformers,
- Note the increase in capacity payment and energy payment, reduction of penalty, as well as a large 3-year incentive (to help ensure that the DR can be used as a planning tool, therefore realizing the investment deferral value)
- Tripling of Tier 2 capacity payments, doubling of Tier 1 payment, 3-year incentive, doubling of the energy payments
- BYOT – Nest, EcoBee, EnergyHub, over 2,000 signups since November 2014, Very cost effective BYOD – Pool Pumps, Freidrick A/C, Quirky, any WiFi enabled devices, already have signups Know your Circuits – Branch Energy Measurement Devices to obtain customer loads by each circuit in their circuit boxes. We intend to identify ways in which we can help customers reduce their loads, manage their energy consumption, and learn more about their energy consumption.
- EEPS authorization ends the end of 2015, however NYS is moving into a new REV regime. For transition years, our department will submit a transition plan to bridge to REV. What is REV? REV is the PSC’s new concept of the utility business model. They are unhappy with the pace of adoption of renewable, distributed generation, so they essentially are looking to push the de-regulation model down to the distribution network. The distribution utility, namely ConEd, will serve as the distribution system platform provider, operating a system and balancing loads, where distributed generators can meet customer demands.
- Previous valuation of costs and benefits based on system-wide average New approach to understanding value based on : Where is your need or at risk areas? Location based solution based on a characterization of the need or risk (in the FSC model: networks/load areas – Network Risk Index (NRI) ranking and % excess capacity What characteristics of the need? Depth of need (MW reduction needed) Resource Availability (Event Duration “width”, Performance) Timing (Day vs. Night, Coincidence with Peak) What should the incentive be? Set based on the relative benefits, i.e. locations with greater value get higher incentives. TRC is total cost – where does the money go? Who pays? Who lays claim to the benefit? Is it cost effective? TRC testing? UCT? SCT? What benefits to include? How to estimate “difficult to value” benefits? The FSC model also has the flexibility to test cost effectiveness through scenario analysis (i.e. differing levels of incentives or program characteristics). Two important pieces of the model are the Grouping of Networks and the Distribution Capacity Value which is covered on the next two slides.