Zero Emission Bus Impact on Infrastructure

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1 Zero Emission Bus Impact on Infrastructure California Transit Association (CTA) Fall Conference Nov 17, 2016 Russ Garwacki Director, Pricing Design & Research Barbara Barkovich Barkovich & Yap, Inc

2 Context Barkovich & Yap, Inc. (B&Y) and Southern California Edison (SCE) worked cooperatively to assist Long Beach Transit (LBT) with its analysis of the electricity cost consequences of its bus electrification project. B&Y participated as a subcontractor to the Center for Transportation and the Environment. CTE/UT-CEM developed a Route Model to assess energy requirements for each bus option on a given route CTE/UT-EUM developed charging profiles to assess time and duration of charge need to meet energy requirement for given bus/route for each charging option B&Y developed a rate model to assess annual cost of energy based on Route Model and Charging profiles SCE provided support for LBT on the types of additional facilities that would be needed to provide service for electrification. It also performed rate analysis for LBT. SCE and B&Y benchmarked their rate models against each other. 2

3 Overview California Air Resources Board has proposed a Zero Emission Bus (ZEB) rule* Applicable to all California Transit Agencies All buses must be zero emission by 2040 Only electric & fuel cell buses qualify as ZEB Impact of TOU Pricing & Demand Charges Rate designs to accommodate different charging models Measures to help reduce total project costs and operating costs * Also known as the Advanced Clean Transit (ACT) regulation 3

4 Electric Rate Design Electric rates include: Volumetric energy charges (cents per kwh, varying by time of use) Demand charges ($ per kw, some varying by time of use, some based on highest demand regardless of time, based on highest 15-minute usage during a billing period) Fixed customer charges ($ per month) Power factor adjustments Electric rate schedules are differentiated by maximum demand in a month and by service voltage Electric rates are set by the CPUC for investor-owned utilities and by city councils or other public entities for publiclyowned utilities CPUC-authorized rates are supposed to be set based on cost of service with costs allocated among different sets of customers based on marginal costs POUs may use embedded costs 4

5 Impact of TOU Pricing & Demand Charges SCE s commercial & industrial customers are served on rates with Time-of-Use (TOU) pricing 1/ with volumetric energy charges and demand charges 2/ The most important element in determining the cost of electricity for electric bus charging is the charging load pattern, which determines TOU energy and demand charges SCE is proposing to change its TOU periods substantially by 2018, as proposed in its 2016 Rate Design Window (RDW) Application This change is a result of the changing net load curve, sometimes called the duck curve, where load net of wind and solar drops during the day and peaks in the late afternoon/early evening, in contrast to current TOU periods where the peak is during summer afternoons Due to the unique nature of commercial EV charging load, SCE adopted several EV pricing options for commercial & industrial customers 1/ Energy is cheapest at night (when there is low demand) and typically most expensive during the day (when there is high demand). Definition is subject to change, pending the California Public Utilities Commission s (CPUC) approval in SCE s 2016 RDW Application (A ). 2/ Recovers utilities fixed costs associated with generation and, in the future, some grid infrastructure required during peak hours. 5

6 Current and Proposed TOU Periods TOU Period Season 1/ Current Proposed 2/ On-Peak Summer Weekdays: 12-6pm Weekdays: 4-9pm Mid-Peak Summer Weekdays: 8am-12pm; 6pm- 11pm Weekends: 4-9pm Winter Weekdays: 8am-9pm Weekdays and Weekends: 4-9pm Off-Peak Summer Weekdays: 11pm-8am Weekends: All Weekdays and Weekends: All except 4-9pm Winter Weekdays: 9pm-8am Weekends: All Weekdays and Weekends: 9pm- 8am Super Off-Peak Winter N/A Weekdays and Weekends: 8am- 4pm 1/ Summer Season: June September; Winter Season: October May 2/ Proposal pending before the CPUC in SCE s 2016 RDW Application (A ) 6

7 SCE s Current & Proposed Commercial EV Rates Rate Schedule Maximum Demand Applicability TOU Periods 4/ Related Demand (FRD) Facilities Charge Offset 1/ TOU Periods Reflect Forward- Looking RPS Conditions 2/ TOU-EV-3 20 kw Applicable for businesses solely for the charging of EVs on a premise or On-Peak: 12 noon 6 p.m. weekdays except holidays Mid-Peak: 8 a.m. 12 noon; 6 p.m. 11 p.m. weekdays except holidays TOU-EV kw public right of way where a Off-Peak: 11 p.m. 8 a.m. separate SCE TOU-EV-6 3/ > 500 kw meter to serve EV charging facilities is required On-Peak: 2 p.m. 8 p.m. Super Off-Peak: 10 p.m. 8 a.m. Off-Peak: All other hours 1/ Waives demand charges for EV charging if the EV demand does not exceed the demand of the associated facility. This structure helps the customer control their electricity costs associated with demand charges. 2/ On-Peak periods are shifted to late afternoon/early evening; Mid-Peak periods are eliminated; and Super Off-Peak periods incentivize late night (and some midday) charging. 3/ New tariff proposal is pending CPUC approval. Advice Letter 3402-E filed on May 5, / Summer Season: June September; Winter Season: October May 7 * Supports move toward transportation electrification; increased adoption of heavy-duty EVs across multiple sectors

8 Zero Emission Bus Charging Models In-Route Only (Decentralized; Frequent) In-Depot Only (Overnight; Centralized; Infrequent) Combination of In-Depot and In-Route Charging Strategy Charging will occur throughout the day during off-/mid-/on-peak rate intervals Charging will occur overnight at the depot with some daytime charging at the depot during off-/mid-peak rate intervals Charging will occur overnight at depot supplemented with inroute opportunity charging Charging Infrastructure Requirements Charger Customer- Side Fast (typically kW) charging station or device (e.g., curbside charging stations incl. overhead or inductive charge system); controlling unit and interface Plug-in Depot Chargers Combination of both depends on agencies and route needs Panel, conduit, breakers, conductors and associated construction Utility- Side Typical utility service upgrades from distribution to transformer 8

9 Charging Trade-offs The voltage and duration of charging is key because demand is measured as usage during each 15-minute period. The highest demand during a TOU period for the month becomes the billing demand for that period. Rate structures with demand charges and lower energy charges benefit customers with high load factors, all else being equal. Lower load factor (infrequent) charging benefits from no or low demand charges. Charging during periods with low demand charges (e.g. mid-peak, off-peak or super off-peak, with only non-tou distribution and transmission demand charges) which also have the lowest energy charges is ideal. But it means must charge only during certain intervals It is possible to optimize charging patterns and rate schedules to minimize electricity costs. This includes optimizing the number and voltage of chargers. Staggered charging events will make best use of equipment and reduce demand charges. Fast charging results in higher demand charges. 9

10 Offsetting Total Cost of a Project SCE s Rule 15 Distribution Line Extensions 1/ and Rule 16 Service Extensions 2/ provide allowances to help customers defray the total cost of a project STEP 1 STEP 2 STEP 3 STEP 4 SCE estimates total installed costs 3/ An allowance is calculated (when applicable) and subtracted from the Step 1 costs The applicant advances /pays 4/ the difference between what is left over after Step 2 Step 1 (in addition to customer responsibility costs) SCE establishes a Ready-to-Serve date ALLOWANCE Annual Net Revenue (distribution only) Cost of Service Factor (15.72%) * Net Revenue: 1,000,000 kwh x $ $/kwh (average distribution rate for large power) = $23,970 1/ Distribution line extensions generally supply power to multiple customers in a given area 2/ Service extensions typically provide power to only one customer or to a single point of service with multiple meters 3/ The total installed cost does not include customer responsibilities (i.e., excavation, trenching, and conduits that the customer pays for and deeds to SCE, including applicable ITCC) 4/ If the customer selected the 50% Discount Option, the customer would advance 50% of the refundable amount, on a non-refundable basis 10

11 Additional Measures to Reduce Total Cost of a Project Monetizing Low Carbon Fuel Standard (LCFS) Credits 1. Agency registers with the ARB and reports the kwh usage for their buses; 2. ARB will award LCFS credits quarterly into the registered agency s account based upon energy usage; 3. The agency is then free to work through a broker or sell these awarded credits on exchanges themselves; and Value of credits is equivalent to 7-15 cents/kwh 4. Revenue generated through credit sales can then be used at the discretion of the agency. Federal, State and Local Incentives AB8: Provides grants and loans for Alternative and Renewable Fuel and Vehicle Technology Program Heavy-Duty Vehicle Incentive Program: Provides up to $110k per vehicle rebate for acquisition of buses but not infrastructure IOUs proposals for infrastructure investments for heavy duty vehicles, including buses Ruling issued on Sept. 14 orders IOUs to file applications for investments and programs by January 20, Utility proposals will focus on infrastructure in non light-duty vehicle segments. 11

12 BACKUP 12

13 Example Non-Residential Rule 15 Refundable Option SCE estimates total installed costs¹ Allowances are calculated (Using the revenue-based allowance formula: Net Revenue Cost of Service Factor) Customer pays advance² SCE establishes a Ready-to-Serve date $100,000 Service Ext + $300,000 Line Ext $400,000 TOTAL $23,970* = $152,481 $400,000 - $152,481 $247,519 5 If the meter is not set within 6 months, SCE begins deficit billing for the allowances granted and monthly ownership charges will be applied to any refundable portion of the advance that has not qualified for refund after one year (review refundable amounts each year for 10 years) ¹The total installed cost does not include customer responsibilities (i.e., excavation, trenching, and conduits that the customer pays for and deeds to SCE, including applicable ITCC) ²If the customer selected the 50% Discount Option, the customer would advance 50% of the refundable amount, on a non-refundable basis * Net Revenue: 1,000,000 kwh x $ $/kwh (average distribution rate for large power) = $23,970 13

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