operational and technical functionalities related to the OpenADR integration. The Grid Export Flattening operational functionality was tested in all events while the Ramping operational functionality was only tested in some events. Events 15-17 replicated CPP events called during the summer (i.e. 4-7pm Peak Period, day-ahead signal), so Sunverge could test and improve dispatch algorithms and capacity forecast accuracy. Table 42. Fall Demand Response Test Events. Event Event Date Advanced Event Period Technical Tests 10 10/12/15 Day of 1pm – 7 pm Yes DRMS OpenADR Communications Capacity available over extended event period 11 10/21/15 Day ahead 5pm - 7 pm Yes Multiple event executions in one day 12 10/21/15 Day of 3 pm - 5 pm Yes Multiple event executions in one day New events can be received while an event is occurring Capacity forecast accuracy 13 10/26/15 10 minutes ahead 4 pm – 5 pm No Multiple event notifications in one day Quick response to emergency DR event Capacity forecast accuracy 14 10/27/15 Day ahead 4 pm – 7 pm Yes Multiple event notifications in one day Capacity forecast accuracy 15 11/11/15 Day ahead 4 pm – 7 pm No Algorithm optimization Performance consistency Capacity forecast accuracy
dispatch, and 3) with the addition of PV with SIS units programmed for customer dispatch. For each of these deployment scenarios, both a “low” penetration and “high” penetration case was modeled. Summary of results Table 49. Summary of Operational Impacts on the Waterman-Grantline Circuit in Each Scenario. Low Penetration High Penetration Baseline PV Only SIS (Utility dispatch) SIS (Customer dispatch) PV Only SIS (Utility dispatch) SIS (Customer dispatch) ENERGY LOSSES Annual Energy Losses (MWh) 343.0 341.4 341.0 341.2 339.6 338.9 339.2 Change in Total Annual Energy Losses (MWh) - -1.6 -2.0 -1.8 -3.4 -4.1 -3.8 EQUIPMENT MECHANICAL STRESS Total Annual Capacitor Switching Operations 116 134 134 134 134 134 134 Change in Total Annual Capacitor Switching Operations - 18 18 18 18 18 18 EQUIPMENT LOADING Total Annual Hours of Capacitor Operation 14,126 6,279 6,279 6,279 6,279 6,279 6,279 Change in Total Annual Hours of Capacitor Operation - -7,847 -7,847 -7,847 -7,847 -7,847 -7,847
Annual Hours of Operation for Capacitor #2 16 0 0 0 0 0 0 Annual of Operation for Capacitor #3 7,872 41 41 41 41 41 41 Adding PV and SIS to the circuit also has a slight impact on the loading of the substation transformer, as Table 413. shows. However, the transformer never exceeds 89% of its rated capacity in any scenario, and is relatively lightly loaded over the course of the year. While the reduced loading from the addition of PV and SIS units might extend the life of a more heavily loaded transformer, the change in loading on the Waterman-Grantline transformer is unlikely to impact the life of the equipment. Table 413. Loading of Waterman-Grantline Substation Transformer in Each Scenario. Low Penetration High Penetration PV Only SIS (Utility dispatch) SIS (Customer dispatch) PV Only SIS (Utility dispatch) SIS (Customer dispatch) Annual Load Factor of Substation Transformer 35.4% 35.3% 35.3% 35.2% 35.2% 35.2% Peak Loading of Substation Transformer 88.9% 88.8% 88.2% 88.8% 87.4% 87.5% Results—Power Quality Table 414 Total Number of 15-Minute Intervals Where One or More Nodes Had a Voltage Violation During the Year. Low Penetration High Penetration Baseline PV Only SIS (Utility dispatch) SIS (Customer dispatch) PV Only SIS (Utility dispatch) SIS (Customer dispatch) Total Annual Events 1,338 1,281 1,278 1,276 1,271 1,245 1,250 Total Annual Events 530 532 532 532 532 546 543
Economic Impacts of Distributed Energy Resources This subsection briefly describes the numerous costs and benefits quantified and included in the case study. Table 51 provides a brief overview of the avoided costs of supplying marginal energy from the utility’s perspective. These costs are avoided if energy consumption is reduced or DERs produce energy and increased if consumption is increased or DERs consume energy, and can have time varying values. The avoided costs have a 10-yr. procedural history in evaluating the cost-effectiveness of distributed energy resources at the California Public Utility Commission (CPUC). Table 51. Utility’s Avoided Cost of Energy Components. Component Description Avoided Energy Cost Hourly wholesale value of energy Avoided Generation Capacity Cost The avoided cost of building new generation capacity to meet system peak loads Avoided Ancillary Services Cost The avoided marginal of providing system operations and reserves for electricity grid reliability, assumed to be 1% of energy cost Avoided Losses The avoided cost of increased resistive transmission and distribution losses due to an increase in end load Avoided Emissions The avoided abatement cost of carbon dioxide (CO2), nitric oxide, and nitrogen dioxide (NOx) emissions associated with the marginal generating resource Avoided RPS The avoided purchases of required renewable generation at prices required to meet a renewable portfolio standard Distribution Deferral Value The time value of money when the peak distribution network load is reduced, and an investment in distribution capacity can be deferred Distribution Operations Avoided mechanical wear on distribution equipment such as tap changing transformers or switching capacitors Table 52 describes the costs and benefits that a utility customer faces when deciding to adopt a DER such as the SIS.
515: Total Reliability Value ($/kW) For a 2-hour battery on Jackson-Sunrise feeders Customer Class Utility dispatch Full Battery all Year Residential $1.20 $1.90 Commercial $126 $201 Industrial $108 $172 Ratepayer Neutral Incentive Analysis In this section we discuss the maximum ratepayer neutral incentives that a utility pay to customers for installing SIS units in the scenarios studied. SMUD customers already receive an SGIP adoption incentive, but this incentive was shown to result in a net cost to non-adopting ratepayers in cases other than the large SIS unit, PG&E demand charge tariff, and high generation capacity price sensitivities under utility dispatch. To calculate the maximum ratepayer neutral incentive, we subtract the customer’s bill savings from the utility benefits shown in the RIM test. Table 515 shows the maximum ratepayer neutral incentive for the base case and sensitivities analyzed in sections 5.5 and 5.6. The table also shows the utility benefits and customer bill savings used to calculate the maximum incentive. The incentive depends on the value that the SIS unit creates for the utility, which can largely depend on distribution deferral value. This results in a maximum incentive that varies based on the location of the SIS unit in the distribution network. The distribution network location is indicated in the column marked Feeder, with JS representing Jackson-Sunrise and WG representing Waterman-Grantline. The column labeled ‘PCT w/o SGIP’ gives the net participant cost or benefit without an SGIP incentive for each scenario. In the ancillary services sales case, we have accounted for the ancillary service revenues as a customer benefit in the No SGIP PCT. There are two cases where the maximum incentive is larger than the SGIP incentive: the large SIS unit sensitivity and the maximum generation capacity price sensitivity. The only case where the maximum ratepayer neutral incentive would be sufficient encourage adoption is the maximum generation capacity price sensitivity.
Table 516. Maximum Ratepayer Neutral Incentives for Adoption of SIS Units Under Utility dispatch. ($/kW-yr.) Case Feeder Utility Benefits Customer Bill Savings Maximum Utility Incentive ($/kW-yr.) PCT w/o SGIP Base Case JS $251 $123 $128 -$248 WG 193 123 70 -248 High DER JS 244 123 121 -248 WG 149 123 26 -248 TOU+CPP Tariff JS 251 110 140 -261 Larger SIS Units JS 265 96 169 -239 Ancillary Services JS 250 119 131 -225 2016 TOU JS 251 137 114 -234 PG&E TOU Tariff JS 251 227 24 -144 PG&E Demand Charge Tariff JS 251 183 68 -184 $250/kW-yr. Capacity Value JS 433 123 310 -248 Summary of Findings The value of customer adoption of SIS units has been investigated from many perspectives and in many sensitivities in the case study above. The only scenario to show a positive TRC benefit is when generation capacity is valued at $250/kW-yr. The only scenario with a positive PCT benefit was under the PG&E TOU tariff. Two scenarios showed a positive RIM benefit: larger SIS units, and high generation capacity price.
Table 61. Existing Storage Pilots and Programs Provider Location Program Name Incentive Type Ownership Type Incentive or Details Program Type Additional Information 1 Green Mountain Power Vermont TESLA Powerwall Monthly Utility Payment for Control Customer $31.76/month incentive Storage Only Utility will discharge battery at specific times to lower their energy costs and capacity and transmission expenses. 17 year pay back 2 Green Mountain Power Vermont TESLA Powerwall None Utility Lease Customer pays $1.25/day Storage Only See above. Interest free 17-year installment plan 3 Green Mountain Power Vermont TESLA Powerwall None Customer Customer can purchase Tesla Powerwall for $6,501 Storage Only No utility control 4 Clean Energy California None Monthly Utility Payment for Control Customer incentive for 50% use of battery and $10/month incentive for 100% use of battery Storage Only Battery vendor neutral 5 Pacific Gas & Electric, Southern California Edison, Southern California Gas, San Diego Gas & Electric California Incentive Program (SGIP) Equipment Incentive Customer $1.31/watt incentive in 2016 and declining 10% every year (incentive structure may change in Storage Only Battery vendor neutral. Storage must be used for load shifting via at least a time-of-use rate and not just back-up 6 Ergon Retail Australia Hybrid Energy Service None - Equipment installed for free Utility Customer pays for 12 months Storage + PV Customer estimated to receive annual savings as well as having back-up Customer automatically participates in DR and will be on a time-of-use tariff with a demand charge based on coincident system peak 7 PowerStream Ontario, Canada POWER.HOUSE Pilot None - Equipment installed for free Utility Customer pays upfront cost and monthly service fee Storage + PV 20 customers and the effort is funded by a grant from the Independent Electricity System Operator (IESO) Conservation Fund 8 Xcel Energy Colorado Innovative Clean None Utility Info not available Storage + PV Xcel will install and test six batteries on the customer side at residences with existing PV and six batteries on the
Figure 64: The proposed FVT is analogous to the rate structure used by cell carriers. Customer Charge. Embedded costs and expenses associated with serving the customer, such as the meter, meter servicing, and customer billing, are recovered through a charge on a ($/customer) basis. Network Subscription Charge. The embedded of the grid are inelastic and do not change dynamically with consumption or time of use. Embedded costs of grid infrastructure should be recovered based on the customer’s size or share of peak demands. A Network Subscription Charge covers the cost of the existing grid infrastructure such as distribution, sub-transmission, transmission, and utility-owned generation assets. This charge could theoretically be created according to location specific grid asset utilization. One type of Network Subscription Charge is a demand charge ($/kW). Demand charges are defined by a customer’s share or usage during the peak demands on the various assets in the electrical network on a cost causation basis. It is important that the demand charge reflects the utility capacity planning and maintenance policies so that it reflects real world costs rather than a synthesized cost allocation. If demand metering is not available, then a monthly average demand charge ($/kW-month) or monthly energy subscription charge ($/kWh) may approximate this value. E3 in its FVT has proposed a Network Subscription Charge based on a rolling 12-month maximum monthly peak energy consumption or average demand in a peak month figure. A charge based on average demand or total consumption can provide an incentive for energy efficiency investments that lower average energy consumption. Dynamic Pricing. The Dynamic Price is calculated using a location and time-varying price on electric energy ($/kWh). The focus of the forward-looking marginal cost prices is to provide customers with clear price signals that allow the customers to make consumption and production decisions based on actual marginal and avoidable cost impacts. Marginal and avoidable costs include locational marginal energy costs, electrical losses, avoidable T&D capacity costs, and avoidable generation, i.e. resource adequacy, capacity costs during peak periods. Avoidable T&D capacity costs reflect potential local network upgrade deferral value and would incentivize behaviors that can help reduce the need for planned distribution or sub-transmission upgrades. Marginal cost prices could also include adders for externalities or non-monetized societal costs such as carbon emissions.