Delivering Innovation: Demand Side Management. Bob Hammond, Energy Services Director City of Richland

Transcription

1 Delivering Innovation: Demand Side Management Bob Hammond, Energy Services Director City of Richland 1 10/30/2015

2 Demand Side Management (DSM) DEMAND SIDE MANAGEMENT (DSM) Programs and Technology that Result in a Reduction of the City s and its Electric Utility Customers Peak Power Usage and Associated Costs 2 10/30/2015

3 City of Richland (RES) Entry into DSM SMART GRID Business Case Assessment UtiliWorks (consultant) Report May 2014 DSM addressed as component of overall assessment Demand Response (DR) Pilot Project Energy Northwest (Aggregator) / BPA Funded January year with Two Optional 6 Mo Extensions RES DR Asset Limited to Voltage Reduction at Substations Track & Tune Energy Demonstration Project BPA Funded / Partner with Energy Smart Industrial City s Pump / Storage Water System as DR Application 3 10/30/2015

4 DSM Project Research Objectives Demand Response (DR) Pilot Project Evaluate the Potential to Reduce the RES Demand Cost (currently approximately $5.2 million / yr) Target 0.5% Demand $ Savings for Each 1% Decrease in Voltage Reduction Determine Seasonal Variability of DR Determine Operational Practicality of Responding to Target of 1 Time Per Week DR Application Move from Pilot to Regular Operational Program 4 10/30/2015

5 DSM Project Research Objectives Track & Tune Project Determine the DR Capabilities of Pump Storage Including Seasonal Considerations Realize Demand Savings Related to Changes in Pump / Reservoir Operations w/o Increase in Energy Usage and with Minor Impacts to Pump Motor Efficiencies Establish a Specific Energy Efficiency Metric to Use for Moving from Pilot to Regular Operational Program 5 10/30/2015

6 DSM Project Conclusions DR Pilot Achieved on Average 0.75% $ Savings for Each 1% of Voltage Reduction (compared to 0.5% target objective) Programs to be Left in Place After Pilot to Use for RES Demand Peak Reduction Practical to Respond to Each DR Call from BPA Avg of 1 to 2 Times per Week Appears to Have Both Winter (Resistive Load) and Summer Applicability as DR Asset 6 10/30/2015

7 DSM Project Conclusions Track & Tune With Pump Storage, Demand Shifting Possible with No Additional Energy Usage and Minimal Pump Motor Efficiency Impacts Real Time Measurement Established in KWhr/gal of Water Pumped Now Reported on SCADA System (Use as Energy Efficiency Metric) Pump Storage as DR Asset Has Limited Summer Applicability Because of Reservoir Operations in High Water Usage Months 7 10/30/2015

8 DSM Where We Are Headed Continue Substation Voltage Reduction and Pump Storage DR Programs to Reduce RES Demand Costs Establish Time of Use Rates in order to Incentivize Customers to Adapt Operations to Realize Demand Savings Add Commercial / Industrial Customers to the DR Demand Response (DR) Pilot Project and Beyond Install Advanced Metering Infrastructure to Allow for Direct Load Control Opportunities for Customers Including Residential 8 10/30/2015

9 Other Technology Related Efforts Continued Efforts for Power Factor Correction Using Fixed and Automatically Switched Capacitor Banks Frees Up Capacity on Distribution Equipment Reduces Losses on Distribution Equipment if Placed Correctly Energy Conservation Efforts Residential and Commercial Programs Including BPA EEI and RES Revolving Loan Programs 9 10/30/2015

10 Summary RES Recognizes Value in Demand Side Management Working to Install Technology for Opportunities Planning to Revise Rate Structure to Incentivize Customers to Participate in DSM 10 10/30/2015

11 Commercial Requirements for Demand Response Resources John Wellschlager Account Executive Bonneville Power Administration 1

12 Objectives of today s presentation Review BPA s requirements under the BP-2016 Rate Period for the acquisition of additional within hour imbalance capacity. Review the process and pricing guidelines for these acquisitions. Provide a short review of the previous years acquisitions in BP Provide a timeline for the coming acquisitions and product descriptions. Highlight the challenges that Demand Response resources have in competing for these acquisitions. Summarize BPA s thoughts on Demand Response. October

13 Background As part of the BP16 Generation Inputs Rate Case Settlement, BPA committed to hold 900 MW FCRPS inc capacity during the months of August through March and 400 MW inc for the months of April through June. In addition to this obligation BPA agreed to acquire additional inc reserves known as Planned Acquisitions (Type1) on a quarterly basis to meet Base Service levels of reliability (99.5%). For the BP16 Rate Period this amount is currently 10 MW a quarter. In order to help firm up the spring period, BPA must also attempt to purchase up to 200 MW at least 30 days ahead of the April, May June time period. BPA also agreed to attempt to acquire on a preschedule basis any additional capacity shortfall caused by operational constraints during the Spring Months beyond the 600 MW we expect to provide as a minimum. When the FCRPS has additional inc reserves beyond the 400 MW during the spring period, these reserves will be utilized first prior to making additional purchases beyond the 600 MW provided. These additional FCRPS incs will be sold at a rate of $0.29/kW-day. October

14 Process & Pricing Guidelines for Spring Purchases Monthly, within-month, and up-to preschedule acquisitions are acquired by Power Services using a Request for Offer (RFO) process. Acceptable bids should balance deployment costs against capacity costs in a way that doesn t create cost shifts between within-hour Imbalance Capacity customers and other transmission customers. Standardized Capacity Term Sheets for quarterly and monthly acquisitions provide boilerplate language for pricing options and operational performance standards. These two page confirms are then adapted for any shorter term purchases (less than one month). In addition to a capacity bid ($/kw-mo), the dispatched energy for an individual agreement is bid as either a % of hourly energy index ($/MWh) or as a gas index and heat rate (note that HR X gas price = $/MWh) For purposes of selection, valuation of each offer is done based on: Total Cost = capacity cost + energy cost x estimated deployments over a given range October

15 Looking back Spring & Preschedule RFO Acquisitions One 25 MW spring block purchase was made in early March 2015 for the May 1 June timeframe. BPA received four offers. Pricing ranged from the high side of $3/kW-mo up to the mid $14/kW-mo level. Rough estimates at that time appeared to support the need for a small spring forward purchase to firm up reserve levels to 900 MW of incs. Part of our strategy was to buy earlier while suppliers still had capacity available. It should be noted that this strategy effectively trades one risk for another. Namely, buying ahead at a cheaper rate but risking not needing what we purchase. Due to the low and slow system run off in 2015, the FCRPS was not operationally constrained during the spring runoff period. This doesn t happen often, but it does happen occasionally. As such, preschedule acquisitions were not necessary this spring due to lack of need. October

16 2015 & 2016 Planned Acquisitions Quarterly Capacity Acquisitions: The amount of quarterly RFOs for the 2016 rate period (Oct. 1, 2015 Sept. 30, 2017) is projected to be 10 MW each quarter. (See Settlement, Attachment 1, section 4.b) However, this amount could increase or decrease over this period depending upon the reserve need placed on BPA. Long Term Spring Acquisitions: BPA will attempt to acquire up to 200 MW of Imbalance Capacity as a block purchase. This will be for the months of April, May and June but could change depending upon the projected need. Minimum bid amounts will be 25 MW flat. BPA will issue two RFOs to acquire this spring imbalance capacity for The first RFO will be issued in November and the second will be issued around the end of February. Preschedule Acquisitions: BPA will continue our Preschedule acquisition program for the April June timeframe based on projected need. Minimum bid amounts will be 25 MW on either a diurnal or flat basis (HLH, LLH or flat) Volume purchased for any period will be based on the amount of curtailment occurring on the FCRPS, projected need for the buying period and remaining budget. This could be up to 300 MW assuming we are successful with our preseason acquisition of the 200 MW. October

17 Product Specifics Capacity type Capacity bid format Energy bid format Minimum bid amount Max deployment Number deployments/ hour Ramp rate Monthly $/kw-mo % of Powerdex Mid-C hrly OR HR & Gas Index* 25 MW flat Up to 90 min 1 (deployment must be for the full amount) 10 min Preschedule $/kw-day % of Powerdex Mid-C hrly index 25 MW HLH, LLH or flat Up to 90 min 1 (deployment must be for the full amount) 10 min * Allowable gas indexes are Stanfield, Malin and Sumas for the flow date as published in the Platt s Gas Daily. October

18 Challenges of Demand Response in BPA s RFO process The availability of most DR resources is required to have recharge periods and frequency limits on deployments. Most conventional resources don t have these limitations. Extremely high reliability is required for any DR resource being used to provide within hour imbalance capacity. The good news is that ENW has thus far done a very good job of meeting this target. RFO s have traditionally been bid with a capacity and energy price. It is not clear at this time how an energy price would be managed with Slice customers to avoid paying them twice. Creating a capacity tag with deployment limits, creates significant internal IT challenges for BPA. BPA s long term imbalance capacity quarterly purchases were decreased, but went up for spring period purchases. August 20, 2015 Generation Inputs Workshop Predecisional. For Discussion Purposes Only. 8

19 Summary thoughts regarding BPA and DR BPA is committed to DR, BUT it has to be very carefully vetted and tested since its being used to manage the reliability of the Balancing Authority. While DR is easy to understand as a concept, it is an immensely complicated product to implement when being used as reliability tool. DR is not necessarily the cheapest resource, despite what some people are saying. However, BPA is taking the long view, because it could be one of the cheapest moving forward. Aggregation is the future of DR. Not single source loads. DR will never solve all of the regions balancing & transmission needs. However, it can provide very meaningful help as a tool in conjunction with other resources. To succeed, DR must be 1) Reliable 2) Cost effective & 3) Easy to deploy/use. October

20 Questions? October

21 Contact Information John Wellschlager Account Executive Bulk Marketing Bonneville Power Administration October