DER Valuation Mihir Desu
Strategen Platform 2
About Strategen 3
Introduction 4
DER philosophy progression This philosophy progression provides guidance for how all aspects related to DER need to evolve including planning & operation, interconnection, markets & price signals and valuation. 5
Major drivers of storage and distributed resources Local Capacity Renewable Energy Wholesale Market Retail Bill Resiliency Penetration Needs Opportunities Management High renewable In high-population Storage is Retail customers Increases in penetration in areas where new participating in are utilizing severe weather some markets has generation or organized storage as a events impacting led to need for transmission are wholesale markets, solution for load grid uptime leads additional expensive to build, often by providing shifting and to customers integration storage is serving as fast frequency demand charge using storage as solutions including a capacity resource. regulation services backup power, management. energy storage. (e.g. PJM Reg-D). especially in the Northeast. 6
Possible services and benefits 7
Current value stack ▪ Energy + losses ▪ No capacity value due to high penetration ▪ No AS value yet ▪ No hedge value to any party because under current policy the energy portion floats to fuel prices ~ 10 cents/kWh for HECO 8
Needed functions ▪ DER energy compensation needs to meet or fall below the fuel rate ▪ DERs need to provide ancillary services and grid support beyond just hosting capacity expansion ▪ DERs need to provide capacity and flexible capacity services ▪ The grid needs to supply enough low cost energy and power to the DER provider so an oversized off-grid system is not justified 9
Future value stack Energy should be locked and cost These services based will reduce fixed costs in the future These services will reduce fixed costs 10
Difference between vertically integrated market and competitive market ▪ VDER for competitive? ▪ VOS or RCP for vertically integrated? 11
Valuation Study: Purpose and Goal 1. Gauge if current compensation is fair 2. Figure out appropriate compensation 3. Determining how DERs can help mitigate system costs and benefit ALL ratepayers You regularly buy product X, salesman comes to you and says “I will give you a 100% substitute product for the same price as I forecast it over 25 years?” 1. What would you say? 2. What if there are extra environmental benefits? 12
Incentivizing Peak Reduction Technologies ▪ Generation and distribution capacity benefits of solar, as a non-dispatchable resource, can be small as peak demand hours are generally later in the day, after peak solar generation hours ▪ This is more significant in regions, such as California, that are experiencing a duck curve and negative pricing in the middle of the day ▪ Storage and/or other DERs could help shift solar generation during those later hours to capture all the generation capacity benefits ▪ Creating price signals to induce this type of behavior is critical VDER tariff sends the proper price signals for efficient and effective grid management during peak hours 13
Illustration of VDER in ISO-NE
VDER Like Approach for New England ISO Structure: ▪ VDER components are not fixed and instead depend on current year ISO-NE market dynamics (i.e., annual compensation to DERs will vary by year) ▪ Capacity DRIPE value lags 3 years because capacity cleared in the current year’s forward capacity auction (FCA) is not called for 3 years ▪ Certain components of the VDER rate may not be applicable to DERs that are already participating in ISO-NE markets 15
VDER Components ▪ Value of environmental attributes of the generation Environmental ▪ Value of RECs to meet RPS requirements or sell into MA SREC market Value ▪ Impacts on RGGI allowances needed/arbitraged ▪ Value of avoided transmission system costs due to demand reduction Transmission ▪ ISO-NE transmission regional network system (RNS) charges Value ▪ ISO-NE reliability and administrative charges ▪ Discussed in next section Distribution Value ▪ Value of avoided capacity costs Capacity ▪ ISO-NE net regional clearing price * DER’s prior year coincident peak Value ▪ Demand reduction induced price effects (DRIPE) ▪ Reflects the avoided cost of energy purchases (and avoided line losses) Energy ▪ ISO-NE real-time Nodal LMP Energy Prices (5 min intervals) Value ▪ Demand reduction induced price effects (DRIPE) ▪ Reflects the avoided cost of ancillary service purchases Ancillary ▪ ISO-NE ancillary market charge * DER’s prior year coincident peak Service Value 16
Environmental Value • Renewable Energy Credits (RECs) Environmental • ACP Value • MA SREC market • Regional Greenhouse Gas Initiative (RGGI) 17
Transmission Value ▪ ISO-NE Regional Network Load (RNL) Charge ▪ Infrastructure: RNS rate (based on annual infrastructure revenue requirement) * IOU’s monthly coincident peak (12-CP) ▪ Reliability: Total ISO-NE payments to resources / RNL monthly peak * IOU’s monthly CP Transmission ▪ Administrative: Tariffed rate (based on annual administrative revenue Value requirement) * IOU’s monthly CP ▪ DER Transmission Value determined by monthly coincident peak * total RNL rate (sum of infrastructure, reliability, & administrative) ▪ Adjusted for IOU-specific line losses 18
Capacity Value ▪ ISO-NE Forward Capacity Market (FCM) Charge ▪ Net Regional Clearing Price (NRCP) = Payments made to Capacity Supply Obligations (CSO) / Sum of Capacity Load Obligations (CLO) ▪ FCM Charge = NRCP * IOU’s previous year’s CP ▪ DER Capacity Value = DER reduction of IOU’s CP * NRCP ▪ Note that this value lags a year because of its dependence on the previous year’s CP ▪ DRIPE Capacity Value Capacity ▪ DER Capacity DRIPE Value is determined by the reduction in the FCA’s Value clearing price due to DERs multiplied by amount capacity called in the FCM ▪ This value is difficult to determine because while the change in the FCA’s clearing price due to DERs can be estimated using the FCA’s supply and demand curves, the amount of capacity called in the FCM will not be determined for 3 years 19
Energy Value ▪ ISO-NE Energy Locational Marginal Price (LMP) ▪ Real-time (RT) Nodal LMPs (5 min intervals) adjusted by IOU- specific line-losses ▪ ISO-NE Net Commitment Period Compensation Charge ▪ Compensates resources for deviations between day-ahead and real-time prices ▪ DRIPE Energy Value ▪ Due to the fact that LMPs are derived incorporating the demand reductions caused by DERs, LMPs are lower than they would be Energy without the presence of DERs Value ▪ DER Energy DRIPE Value estimated based on average of DRIPE impacts in 2013 and 2015 reports on Avoided Energy Supply Costs (AESC) in New England 20
Ancillary Service (AS) Value ▪ ISO-NE Ancillary Market Charge ▪ Regulation Market ▪ Total hourly cost of resource regional compensation / Region’s RT Load Obligation (RTLO) ▪ Forward Zonal Reserves (only during peak hours) ▪ Total hourly cost of zonal resource compensation / Zonal RTLO ▪ RT Zonal Reserves (all hours) ▪ Total hourly cost of zonal resource compensation / Zonal RTLO ▪ Transitional Demand Response (DR) ▪ Total cost of regional resource compensation / Regional RTLO ▪ DER AS Value is estimated by summing the AS rates above (AS Market Ancillary Charge) and multiplying by the DER reduction of IOU’s pervious year CP Service Value ▪ Note that a DRIPE value for ancillary services also theoretically exists 21
VDER Tariff: Dispatchable Solar DG (1-Year Snapshot) ▪ Assumptions Revenue from VDER Tariff ▪ System Size = 9.28 kWdc 250.00 ▪ Line Losses = 6.47% (Unitil) 1 ▪ Generation Profile = PV Watts hourly 200.00 Monthly Revenue ($) ▪ Weather Data = Concord, NH TMY 150.00 ▪ REC Value = $37.03/MWh 2 ▪ LMP = NH Zone 100.00 ▪ Notes 50.00 ▪ Does not include DRIPE values for capacity 0.00 ▪ Nodal LMP will differ depending on actual DER’s location ▪ RGGI value is not easily quantified Energy Capacity Ancillary Services ▪ Implied value of generation ($/kWh) ~ 0.19 Transmission REC 22
Rate Comparison for 100% Dispatchable Solar DG (1-Year Snapshot) Original NEM Tariff vs. VDER Tariff 250 200 Monthly Revenue ($) 150 100 50 0 Original NEM VDER 23
Approaches to Distribution Valuation
Distribution Valuation Strategies ▪ Through rate cases distribution companies know their average marginal system cost ▪ Locational granular values aren’t typically available ▪ Traditional solutions (eg. Transformers, lines) have a known cost and capabilities. The following details are well established: Various methods to value grid have been considered in the past ▪ Timing ▪ Load forecast and work backward with known lead times ▪ Location Similar to New York DRV process ▪ Controllable, install equipment in area required ▪ Amount/Capacity Central Hudson & LNBA ▪ Size and rating of equipment known ▪ Availability ▪ Generally understood but system planning does utilize redundancy for failures General value vs. locational value 25
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