1. 0 LMP+D RATE FOR DISTRIBUTED ENERGY RESOURCES IN NEW YORK AEEI – ACENY – NECEC* Proposal to NY Public Service Commission *Developed with support from Clean Power Research

2. 1 Advanced energy community perspective New roles for monopoly DSP provider: Procure energy from local and central sources Enable increased deployment of DER LMP+D compensation mechanism should apply… … to all DER technologies … to generation and load reduction … to dispatchable and non-dispatchable resources … to BTM, grid sided, and shared resources

3. 2 Summary of Proposed Rate Hourly variable prices ($/kWh) All components of LMP+D, per BCA Order Applicable to consumption and generation Exports valued same as BTM DG consumption Retroactively calculated at bill settlement Components Included Avoided Generating Capacity (ICAP) Avoided Energy (LBMP) Avoided Transmission Capacity and O&M Avoided Transmission Losses Avoided Ancillary Services Wholesale Market Price Impacts Avoided Distribution Capacity Infrastructure Avoided Distribution O&M Costs Avoided Distribution Losses Externalities

4. 3 Gradual Implementation Grandfathering of NEM for existing projects o Based on LMP+D implementation timeline not just systems in operation today Retain NEM for DG customers that are “net importers” Opt-in for most DER customers initially Transition to default for some DER customers/projects o BTM DER with “significant” annual net export o Remote net metering o Community DG o All DER currently not eligible for NEM

5. 4 Illustration of Hourly Variable Prices* High price differential: Energy costs depend on load Capacity costs allocated by load Hourly loss factors vary by square of load * Only two components shown for simplicity. Actual rate would include all elements of LMP+D.

6. 5 Example Calculation: ICAP Assume Cost = $100 per kW-year Hourly price proportional to Loss of Load Probability (LOLP) Resulting price ranges from $0 to $1.75 per kWh over year Top 600 hours average $0.14 per kWh Top 600 hours Load (MW) Hourly Price ($/kWh)

7. 6 Applicability DER TypeDER CharacteristicsStandard rate/NEMLMP+D Existing NEMExisting DG, incl. CDG & RNMGrandfatheredOpt in Future BTM DG that currently qualifies for NEM Sized for meeting local consumption DefaultOpt in Sized for net annual export (>120% of annual consumption) Default initiallyOpt in initially, then default BTM DG w/o export Any sizeDefaultOpt in Community DG LMI and opportunity zonesDefaultOpt in (entire project) All other projectsn/aDefault RNMAny DG that currently qualifies for RNM Default initiallyOpt in initially, then default Other BTM DER (non DG) EE, storage not paired with solar, DR, EVs Default if no export; Locational adder for EE Opt in if no export; Default if export anticipated All Other DER  DG not qualifying for NEM, RNM or CDG  Non-BTM DER  Community microgrids  No size limits n/aDefault (Could also contract directly with utility for services)

8. 7 Rationale for Hourly Ex-Post Prices Prices are load-dependent o Calculated based on actual loads and costs Dispatchable DERs are “self-scheduled” o Value depends on when DER is actually operated Sends more accurate price signals o DER installed in highest value locations o DER operated at highest value times

9. 8 Technology Examples Energy Storage Charge at lower cost; discharge at higher cost Narrower pricing peaks: lower energy requirements, lower capital cost Load Management/ DR High value for peak shifting (automated DR, smart thermostats, building precooling, ice storage, etc.) Fuel Cells Capture highest prices through dispatch Solar LMP+D expected to be similar to VOS Solar + storage looks interesting West-facing or tracking systems could receive higher value

10. 9 Benefits / Implications / Challenges Benefits Simple rate design o No discrete demand charges o Maintains $/kWh structure Does not require additional verification of performance, just hourly metering and monthly settlement Implications/Challenges Requires interval metering ahead of AMI rollout o Could leverage private investment in DER monitoring Market may require near- term price stabilization measures

11. 10 Options for Price Stability Price stability is important for financing and developing compelling customer value propositions Options o Fix input parameters for several years for all participants (prices, investment schedule, SCC benefit) o Fix input parameters for new entrants (hourly prices would depend on location, hour, and year of entry) o Fix hourly prices for day-ahead dispatch (forecast prices are used for bill settlement) o Front-loading payments for offsetting future utility capacity spend If DER investment does not materialize, can consider adders/incentives

12. 11 Implementation Analytical studies to validate methodology o Cost-effectiveness studies by technology and by utility, based on back- calculated LMP+D rates o Bill impact studies (long-term) Utility/Agency websites o Simple, customer-facing information o Back-calculated hourly prices for 3 years (downloadable) o LMP+D bill calculators for customer screening Price forecasting services (utility or private) o Fully-loaded prices o Long-term (for investment) and short-term (for dispatch) o Utilities publish relevant data (hourly DSP loads, input costs/prices, expansion schedules, etc.) o Services forecast local loads and corresponding prices, available via web services (machine-readable, “SaaS”)

13. 12 Conclusions AEEI strongly supports the Commission’s objectives in developing LMP+D The proposed LMP+D rate: o Would be rolled out gradually based on applicability considerations and after quantitative studies, education, and outreach o Would incorporate the BCA Framework Order at a retail level o Would stimulate new DER investments and technologies in alignment with system needs

14. 13 www.aee.net/aeei / @aeenet / Washington DC San Francisco Boston / powersuite.aee.net Thank You! Ryan Katofsky, Sr. Director, Industry Analysis Advanced Energy Economy rkatofsky@aee.net