The CCA Handbook. Chapter 12 Load Profiling & Distribution Loss Factors. Version 2.0 May 1, 2015

Transcription

1 The CCA Handbook Chapter 12 Load Profiling & Distribution Loss Factors Version 2.0 May 1, 2015 Southern California Edison Chapter 12, Page 1

2 12.1 Load Profiling Introduction Load profiling is the process of taking the cumulative kilowatt-hour (kwh) usage of a customer over a billing cycle and assigning it to individual hours in the cycle, based on the aggregate characteristics of the customer class in which the customer resides. Statistically valid methods are used in the assignment process. Southern California Edison (SCE) provides statistical load profiles in place of interval metering allowing load serving entities such as CCAs to use the load profiles as Settlement Quality Meter Data in accordance with ISO Tariffs. ISO tariffs require that, for ISO energy settlement, Settlement Quality Meter Data be provided which can be either (1) an accurate measure of the actual consumption of Energy by each Scheduling Coordinator Metered Entity in each Settlement Period (e.g. interval meter data), or (2), a profile of that consumption derived directly from an accurate cumulative measure of the actual consumption of energy (e.g. utility provided load profiles for a given customer class). Originally for use in Direct Access, SCE created statistical static load profiles for all 14 rate groups in October 1997, for use in 1998 (For a list of the rate groups, please refer to section 16.5). SCE implemented dynamic load profiling for residential (Domestic-Single/Multiple), Small Commercial (GS-1), and medium commercial/industrial (GS-2) on May 18, After this date, no party may use the static load profiles for these three rate groups in billing or settlement. All other rate groups static load profiles are updated in December of the current year, for use in the following year, e.g. December, 2007, for use in The static profiles are updated annually by using the most recent three years of available historical load profiles. In addition, subject to the Commission approval, SCE may update the static profiles using more advanced statistical techniques Static Load Profiles Originally for use in Direct Access, SCE created statistical static load profiles for all 14 rate groups established in October 1997, for use in 1998 (For a list of the rate groups, please refer to section 12.5). These rate groups are the same rate groups that were used in rate design in the 1995 and 2003 General Rate Cases. The only difference is that we provided separate profiles for two subgroups of the Domestic rate group: single/multiple and master metered accounts. The static load profiles are posted on the load profiles webpage: Southern California Edison Chapter 12, Page 2

3 Each profile represents a class average annual profile, one for each rate group developed using a three-year average of the most recent three years of historical load research data. This simplified approach has been proposed for interim use, pending future Commission action on alternative methodologies for the development and use of load profiles. To develop the static load profiles in compliance with D , SCE uses the existing final sales level load profiles for the most recent three years for each rate group. The final sales level profiles are developed in the process of creating the Annual Rate Group Load Studies. The Load Research group at SCE has been creating the Annual Rate Group Load Studies since For a detailed description of the methodology used in creating the Annual Rate Group Load Studies, please refer to our website at: To create the static load profiles for a particular year, SCE first created monthly day-of-week average profiles for each of the most available three years. This resulted in 84 (12months x 7 days) profiles. We also created eight separate profiles, one for each holiday in the year. Then we took the average, over three years, of each of these 92 profiles. Each day in the year was assigned an average profile based on the month and day of the week. For example, the Friday, April 1, 2008 profile is the average of the profiles for all Fridays in April of 2004, 2005, and SCE updated the static load profiles for 11 rate groups for use in 2008 by using the same methodology as for its 1998 through 2007 load profiles, except that they were updated by using annual load profiles Dynamic Load Profiles SCE implemented dynamic load profiling for residential (Domestic- Single/Multiple), small commercial (GS-1), and medium commercial/industrial (GS-2) accounts. CCAs should use the dynamic load profiles for the above three rate groups in settlement and billing Obtaining Load Profile Information from SCE Information on all load profile classes is provided to CCAs upon completion of the Community Choice Aggregator (CCA) Service Agreement. CCAs are informed of the load profile identification number automatically through the Community Choice Aggregation Service Request (CCASR) process. SCE provides load profiling information for all rate groups to CCAs in order to allow them to schedule power, settle with the ISO, and compute bills for all customers. Both static and dynamic load profiles are available for downloading at: Southern California Edison Chapter 12, Page 2

4 The same website also contains information related to the methodology of creating the static load profiles, historical average load profiles, format of the files, and other related information. The load profiles are also available on The Meter Data Management Agent (MDMA) server (restricted access) SCE Load Profiles and Corresponding Rate Schedules SCE customers receive service on several dozen rate schedules. In order to analyze the loads of different types of customers, customers have been classified by rate schedules into 15 rate groups. The following table contains the mapping of customers to each of the 15 groups. Southern California Edison Chapter 12, Page 3

5 Southern California Edison Load Profiles and Corresponding Rate Schedules Customer Class (Rate Group) Load Profile ID Description Rate Schedules Domestic Dom-S/M Domestic Single/Multiple D-CARE, D-CARE-SDP, D-CARE- SDP-O, D-FERA, D-FERA-SDP, D-FERA-SDP-O, D-PG-S, D-S, D- S-CARE, D-S-FERA, D-SDP, D- SDP-O, DE, DE-FERA, DE-FERA- SDP, DE-FERA-SDPO, DE-S, DE-SDP, DE-SDP-O, DOMESTIC, TD-A-C-SDP, TD-B-C-SDP, TD- TEV-C-SDP, TD-TEV-SDP, TD- TEV-SDPO, TDE-TEV-SDP, TDE- TEV-SDPO, TOU-D-A, TOU-D-A- C, TOU-D-A-SDP, TOU-D-A- SDPO, TOU-D-B, TOU-D-B-C, TOU-D-B-SDP, TOU-D-T, TOU-D- T-CARE, TOU-D-T-SDP, TOU-D- T-SDPO, TOU-D-TEV, TOU-D- TEV-C, TOU-DE-A, TOU-DE-A- SDP, TOU-DE-B, TOU-DE-B- SDP, TOU-DE-T, TOU-DE-T- SDP, TOU-DE-TEV, TOU-DET- SDPO, TOU-DT-C-SDP, TOU-DT- C-SO, TOU-EV-1 Domestic Dom-MM Master Metered DM, DM-CARE, DMS-1, DMS-2, DMS-3 LSMP GS-1 General Service, Non-demand Metered, Small Commercial GS-1, GS-1-APS-E, GS-1-CIF, GS-1-G-S, GS-1-SCE, TGS1- RTP, TOU-EV-3, TOU-EV-3-A, TOU-GS1A, TOU-GS1A-AE, TOU-GS1A-AEC, TOU-GS1A-C, TOU-GS1B, TOU-GS1B-AE, TOU-GS1B-AEC, TOU-GS1B-C, TOU-GS1B-S LSMP TC-1 Traffic Control TC-1 LSMP GS-2 General Service, Demand Metered, Medium Commercial/Industrial GS-2, GS-2-AE/GS1, GS-2-APS- E, GS-2-CARE, GS-2-SCE, GS- 2/GS1, TOU-EV-4, TOU-GS2A, TOU-GS2A-AE, TOU-GS2A-AEC, TOU-GS2A-C, TOU-GS2B, TOU- GS2B-AE, TOU-GS2B-AEC, TOU-GS2B-C, TOU-GS2B-EDW, TOU-GS2B-S, TOU-GS2B-SAE, TOU-GS2R, TOU-GS2R-AE LSMP TOU-GS General Service, Time-of-Use, Medium Commercial/Industrial AG&P PA-1 Small Agriculture & Pumping PA-1, PA-1-SCE AG&P PA-2 Agriculture & Pumping, Demand Metered AG&P Ag-TOU Agriculture & Pumping, Time-of- Use TGS3-C-CPP, TGS3-CPP, TGS3- RTP, TOU-GS3-A, TOU-GS3-B, TOU-GS3-B-C, TOU-GS3-B-S, TOU-GS3-BAES, TOU-GS3-R, TOU-GS3-SOP, TOU-GS3A-AE, TOU-GS3B-AE, TOU-GS3B- EDW, TOU-GS3R-AE PA-2, PA-2-I, PA-2-SCE TOU-PA-ICE, TOU-PA-ICE-I Southern California Edison Chapter 12, Page 4

6 AG&P TOU-PA-2 Agriculture & Pumping, Time-of- Use AG&P TOU-PA-3 Agriculture & Pumping, Time-of- Use Large Power TOU8-SEC General Service, Time-of- Use,Large Power(>500 kw), Secondary Voltage (Below 2 kv) Large Power TOU8-PRI General Service, Time-of- Use,Large Power (>500 kw), Primary Voltage (2 kv - 50 kv) Large Power TOU8-SUB General Service, Time-of- Use,Large Power (>500 kw), Sub-Transmission Voltage (Above 50 kv) TOU-PA2-RTP, TOU-PA2A, TOU- PA2B, TOU-PA2B-S, TPA2- SOP1, TPA2-SOP2 TOU-PA3-RTP, TOU-PA3A, TOU- PA3B, TOU-PA3B-S, TPA3- SOP1, TPA3-SOP2 MARCH-AFB, TOU-8-A, TOU-8- AE-S, TOU-8-B, TOU-8-B-APSE, TOU-8-B-S, TOU-8-CPP, TOU-8- EDW, TOU-8-R, TOU-8-R-APSE, TOU-8-RTP, TOU-8-RTP-S, TOU- 8-S MARCH-AFB, TOU-8-A, TOU-8- AE-S, TOU-8-B, TOU-8-B-APSE, TOU-8-B-S, TOU-8-CPP, TOU-8- EDW, TOU-8-R, TOU-8-R-APSE, TOU-8-RTP, TOU-8-RTP-S, TOU- 8-S MARCH-AFB, TOU-8-A, TOU-8- AE-S, TOU-8-B, TOU-8-B-APSE, TOU-8-B-S, TOU-8-CPP, TOU-8- EDW, TOU-8-R, TOU-8-R-APSE, TOU-8-RTP, TOU-8-RTP-S, TOU- 8-S Street Lighting St_Ltng Street and Area Lighting AL-2, AL-2-A, DWL-A, DWL-B, DWL-C, LS-1-ALLNITE, LS-1- MIDNITE, LS-1-TAP, LS-2, LS-2, LS-2-4, LS-2-B, LS-3, OL-1, OL-1- ALLNITE, OL-1-MIDNITE Southern California Edison Chapter 12, Page 4

7 12.6 Load Profiling and Distribution Loss Factor Protocols 12.6.A Applicability 12.6.A.1 This protocol can be used by all CCAs to report hourly energy consumption for their end-use customers in SCE s service area that do not have an hourly interval meter and are eligible to use load profiles to allocate cumulative meter usage into hourly intervals A.2 The purpose of this protocol is to convert non-hourly (monthly) usage recorded at the point of metering to hourly received energy at the UDC-ISO interconnection point for use in settlement with the ISO A.3 This protocol does not need to be used by CCAs for forecasting or customer billing B Conventions and Definitions 12.6.B.1 The time when a meter is read is defined as 11:59 p.m. of the day prior to when the meter is actually read B.2 The Billing Cycle is defined to start at 12:00 a.m. on the day of the prior meter read, and to end at 11:59 p.m. of the day before the most recent meter read. Example: the billing cycle for a meter read on April 20 and May 20 starts at 12:00 a.m. on April 20 and ends at 11:59 p.m. on May B.3 Monthly Usage is defined as the difference between the most recent meter read and the previous meter read adjusted for any necessary corrections B.4 At least five decimal points of accuracy should be maintained in hourly energy calculations. Final reported hourly kwh values should maintain at least two decimal points of accuracy C Data Sources 12.6.C.1 SCE will provide the CCA with the customer s rate group (used to identify the appropriate load profile) and distribution loss factors category after a CCASR is submitted. Southern California Edison Chapter 12, Page 5

8 12.6.C.2 SCE implemented dynamic load profiles for Domestic, GS-1 and GS-2 rate schedules, beginning with data for May 18, Their use is mandatory and no party may use static load profiles for these rate schedules. Currently, SCE posts the dynamic load profiles within three working days after the transaction day. Dynamic load profiles are available at the following Internet address: C.3 Each rate group static load profile consists of hour days. Static and dynamic load profile data for each hour represents the rate group s usage (average kw for the hour) C.4 SCE s Distribution Loss Factors are available by hour and by customer voltage level. These loss factors are based on a system load forecast and will be available one day prior to each transaction day. Distribution Loss Factors will be available at the following Internet address: rect-access/operations/ 12.6.C.5 Where SCE is responsible for metering, SCE will maintain customer usage data, meter reads, and customer account number on a Meter Data Management Agent server for retrieval by CCAs D. Hourly Energy Calculation 12.6.D.1 Each CCA will need to maintain customer rate group and distribution loss factor category information for each of its customers D.2 Each customer s hourly usage (meter level) is computed using cumulative energy usage over the billing cycle from the MDMA server and hourly load profile information for the billing cycle, as extracted from the applicable sources identified in section 12.6.C.1, 12.6.C.2, and 12.6.C.4 above. The steps are as described in item 12.6.D.4 below D.3 CCAs will calculate the load profile as a fraction from the load profiling data posted on the Internet. Sum the hourly load profile kw values for all days of the billing cycle, for the customer load profile rate group. Divide each hour load profile kw value by the sum derived above, to compute the hourly fraction of usage. Customer s hourly usage in each hour is the billing cycle usage times hourly fraction calculated above. Southern California Edison Chapter 12, Page 6

9 Example: Meter read on April 20 and May 20, usage 600 kwh. Customer s load profile rate group is residential. The sum of the hourly load profile kw for April 20 through May 19 is Hour 1 of April 20 load profile kw is kw. The hourly fraction of usage for hour 1 of April 20 is 0.405/ = Then the hourly usage for this customer in hour 1 of April 20, is equal to 600* = kwh D.4 For customers with Time-Of-Use meters, that is meters which record usage by on-peak, mid-peak, off-peak periods, load profiling should be performed separately with the data for each TOU period. Sum the hourly load profile kw values for all days in the billing cycle to create separate totals for each TOU period for the customer load profile rate group. Divide each hour load profile kw value by the sum derived above, to compute the hourly fraction of usage for each TOU period. Customer s hourly usage in each hour of the TOU period is the billing cycle usage for each TOU period times hourly fraction calculated above. For example, meter read on April 20 and May 20, customer rate group TOU-GS-2, customer s mid-peak period usage is 10,000 kwh. The sum of the hourly kw for the mid-peak period of April 20 through May 19 is 18, The hourly fraction of mid-peak usage for hour 9 of April 20 is /18, = Then the hourly usage for this customer in hour 8 of April 20, is equal to 10,000 kwh * = kwh D.5 The hourly usage (for ISO reporting) will be calculated by multiplying the hourly usage (meter level) by the appropriate distribution loss factor. Example: For the example in 16 above, customer s distribution loss factor category is secondary. For hour 1 of April 20 the distribution loss factor is The hourly usage reported to ISO is then equal to kwh *( ) = kwh. Southern California Edison Chapter 12, Page 7

10 12.6 Load Profiling and Distribution Loss Factor Protocols 12.6.A Applicability 12.6.A.1 This protocol can be used by all CCAs to report hourly energy 12.7 Distribution Loss Factor Overview The estimation and utilization of Distribution Loss Factors (DLFs) is critical to the integrity of the scheduling and settlements processes. The presence of large numbers of market participants, new complex processes and procedures, and new metering and data communications systems creates a potential for increased lost energy in the distribution system. Minimizing the potential for such increases requires development of sound methodologies for estimating DLFs, and implementation of appropriate monitoring and enforcement procedures to ensure compliance with market rules. This report addresses the DLF methodologies and their utilization, while monitoring and oversight procedures are addressed more fully in the Retail Data Quality and Integrity Supplement filed in conjunction with this report A. Report Background On May 6, 1997, the California Public Utilities Commission (CPUC) issued Decision No in its Electric Restructuring proceeding. The decision, among other things, directed Pacific Gas and Electric Company (PG&E), Southern California Edison Company (Edison), and San Diego Gas and Electric Company (SDG&E) to meet with interested parties to discuss issues surrounding retail settlement and information flows necessary to implement Direct Access. A workshop was convened on July 7, and a workshop report was submitted to the CPUC on July 25, The workshop report recommended that several sub-committees continue collaborative efforts on a number of high-priority areas and file supplemental reports on August 15, Methods for calculating DLFs was one of these highpriority areas. Through a series of sub-committee meetings, the parties identified potential processes for estimation and utilization of DLFs in the new energy market. On August 1, 1997, the Commission issued Decision No in the Ratesetting Proceeding, which, among other things, directed the Utility Distribution Companies (UDCs) to implement a process to calculate hourly DLFs. The Commission also directed that compliance tariffs implementing hourly DLFs be filed by each UDC. 1 The purpose of this supplemental workshop report is to: discuss how DLFs are used for scheduling and settlement purposes; 1 Edison s proposed DLF methodology is set forth in an Advice Filing dated August 18, Southern California Edison Chapter 12, Page 8

11 describe the proposed UDC methodologies for estimating hourly DLFs; discuss the significance of DLFs and Unaccounted For Energy (UFE) in the ISO Imbalance Energy calculation; and provide the technical specifications (e.g., protocols and data formats) for DLF information flows B. Recommendations to the CPUC This report is the result of a collaborative effort involving various endusers, scheduling coordinators, energy service providers, the Office of Ratepayer Advocates, and the UDCs. Based on the sub-committee s input, the UDCs recommend that the Commission approve the following: the UDC-specific DLF methodologies proposed herein; the provision of specific DLF formulae by October 15, ; the information flow process (communication protocols and data formats) necessary to make the DLF information readily available for use by market participants; and the potential enhancement of the UDC-specific proposed DLF methodologies prior to 1/1/ Distribution Load Factor Definition and Utilization 12.8.A. DLF Definition The general definition of the DLF is the following: The DLF, when multiplied by a distribution level end-use meter measurement, provides an estimate of the load at the corresponding ISO/UDC interface (grid level). In equation form this is shown as, Egrid = DLF Edist (1) where Egrid represents an energy measurement at corresponding ISO/UDC grid interface and Edist represents a distribution level end-use meter measurement. The DLF may be characterized via two distinct approaches: 1) distribution line losses only and 2) total distribution system losses. The primary difference between the two alternatives involves the treatment of meter error and energy theft, as described below A.1 Distribution system line losses (DLL) represent: losses due to resistance in the distribution lines; and transformer core losses. 2 This recommendation is not applicable to Edison as it has proposed a specific DLF formula in its August 18, 1997 advice filing. Southern California Edison Chapter 12, Page 9

12 12.8.A.2 Total distribution system losses (TDL) represent: distribution system line losses (see DLL above); metering error: the difference between the actual electric usage at the meter and the recorded meter read plus any differences due to malfunctioning meters; and energy theft: the deliberate and unauthorized use of energy. DLFs can be produced using either approach. If the DLF corresponds to distribution system line losses (DLFDLL), then the following equation provides the relationship between the distribution system line losses and the DLF: EDLL = (DLFDLL - 1) Edist (2) where EDLL represents the energy corresponding to distribution system line losses. The application of DLFDLL to applicable end-use meter data will be called the DLFDLL-Methodology. Similarly, if the DLF corresponds to total distribution system losses (DLFTDL), then the following equation provides the relationship between the total distribution system loss and the DLF: ETDL = (DLFTDL - 1) Edist (3) where ETDL represents the energy corresponding to total distribution system losses. The application of DLFTDL to applicable end-use meter data will be called the DLFTDL-Methodology B. DLF Utilization The uses of DLFs may include: the ISO and PX mandated use of DLFs to adjust end-use meter data up to a grid level measure (for submittal to the PX and ISO by PX participants and Scheduling Coordinators); the potential use of DLFs by Scheduling Coordinators to estimate and prepare balanced grid level generation and load schedules; and the potential use of DLFs by UDCs to prepare average PX prices for billing and CTC calculation. In anticipation of these uses, the DLFs will be posted for use following the submittal of the UDC demand bid in the day ahead market (the DLFs are based on the UDC internal system load forecast), and prior to the time when SCs are required to submit their preferred schedules. This process results in the day ahead posting of daily DLF tables, by UDC, consisting of 24 hourly DLFs based on the UDC s system load forecast, for each service voltage level. The UDC s system load forecast includes all bundled and CCA customers on the UDC s distribution system. The DLF timing process is illustrated in Figure 1. Southern California Edison Chapter 12, Page 10

13 Day 0 Trading Day Day 1 Day 38 Day 41 10:00 AM: SCs submit preferred day-ahead (Day 1) schedules to ISO by this time. 7:00 AM to 10:00 AM: Calculate DLFs based on internal UDC system load forecast and post DLFs. 7:00 AM: UDCs provide demand bid for day-ahead (Day 1) market and submit it to PX. PX participants must submit settlement ready data (corresponding to Day 1) to the PX by Day 38. DLFs must be applied to meter data to obtain settlement ready data. SCs must submit settlement ready data (corresponding to Day 1) to the ISO by Day 41. DLFs must be applied to meter data to obtain settlement ready data. Figure 1: Timeline for DLF posting and usage 12.9 Distribution Load Factor Criteria and Methodologies In the RSIF sub-committee sessions held during July and August, 1997, the parties supported the development of interim, implementable methods for DLFs as of 1/1/98. These interim methods could be utilized for up to one year while the parties study enhancements to the various DLF calculation formulae currently under consideration. These enhancements could then be incorporated into the calculation process and information flow. (See Section 5 for more details on the information flow designs being considered for 1/1/98 implementation.) 12.9.A. DLF Design Criteria Based on feedback obtained during RSIF sub-committee sessions, the parties reached consensus on the criteria that a DLF estimation methodology should meet. These criteria are shown below: 12.9.A.1 The calculations should be based upon hourly UDC system loads A.2 The calculations should vary by service voltage levels (i.e., subtransmission as appropriate, primary and secondary) A.3 The calculations can vary by UDC as long as the output is provided in a consistent manner (e.g., communication protocols and data formats). Southern California Edison Chapter 12, Page 11

14 12.9.A.4 The calculations can be based solely on either engineeringmodeled distribution line losses, or on historical distribution system losses which also include meter error and energy theft estimates A.5 The DLFs should be available prior to the trading day for use as day-ahead scheduling tools A.6 The DLFs based on the day ahead UDC system load forecast will be used for settlement purposes and may be used for scheduling purposes as well. The UDCs considered providing two daily sets of DLFs. The first set, based on day-ahead UDC forecasted system load, could be used for scheduling and by UDCs to prepare an average PX energy price for billing and CTC calculation. The second set, based on UDC actual system load, would be used for settlement purposes. Utilizing this practice would minimize the small amount of error introduced into settlements by the difference in DLFs based on system load forecast vs. system load actual. However, during the sub-committee collaborative process, the majority of parties felt that the added complexity associated with using two sets of DLFs overshadowed the small increase in accuracy. Therefore, it was decided to base DLFs on the UDC forecasted system load. The UDCs agreed to reevaluate this decision during the overall review of the DLF methodologies prior to 1/1/ B. SCE s Proposed DLF Methodology The following SCE methodology is for use in the SCE s service area only. SCE recognizes the desirability of adopting a single DLF methodology. However, in the interest of implementing DLFs by 1/1/98, and with the concurrence of the sub-committee, each UDC is proposing a method based on that UDC s previously approved general rate cases. The UDCs were able to reach consensus on providing DLFs: for each hour; by service voltage level; and based on the day-ahead UDC system load forecasts. SCE s distribution loss factors will be determined by a formula for each service voltage level that relates hourly losses to hourly system loads. These formulae are based on Edison s 1992 Loss Allocation Study, which calculates energy losses during the entire year and demand losses at the time of system peak. This methodology uses load flow models to calculate peak and annual losses by subtracting the total output of the system from the total input of the system at the subtransmission, primary distribution, and secondary distribution levels. These data will be used to derive a formula for each Southern California Edison Chapter 12, Page 12

15 of the three service voltage levels that will estimate hourly distribution losses for any level of hourly load. SCE models hourly distribution losses as three components: 1) resistance line losses, which vary with the square of load; 2) core transformer losses, which are a function of transformer inventories and are constant with respect to load; and 3) other losses, assumed to be a linear function of load (constant percentage). These other losses reflect unmeasured usage, such as energy theft and meter error, as well as the error associated with estimating the first two terms in the formula. Mathematically, for each hour i: where C represents core transformer losses, R Loadi 2 represents resistance line losses, and A Loadi represents other losses including errors associated with estimating the first two terms. The formula can be solved iteratively for R and A using loss and load data at the time of system peak from the 1992 study, such that annual energy losses estimated using the formula match actual annual energy losses measured in the 1992 study. The second term of the formula assumes that resistance on the system is constant throughout the year. In reality, load and generation patterns vary throughout the year, so resistance of the system, the R value, also varies. Therefore, the value of A includes the effects of errors in estimating R in addition to energy theft, meter error, and other unmeasured usage. Losses can be expressed as a percentage of load by dividing each term by load: Once the values of C, R, and A have been estimated using the historical data, hourly percentage loss factors at different voltage levels can readily be calculated by inputting hourly load forecasts and actuals into the formulae The Relationship of Imbalance Energy and UFE to DLFs As a result of the application of DLFs to end-use meter data, the DLFs are an implicit component of the ISO Imbalance Energy equation and the UFE equation. This section provides the following: 2 Losses i C R Loadi A Loadi definition of Imbalance Energy (IE); definition of Actual Imbalance (AI); definition of UFE; and DLF Effects on Imbalance Energy. C Percentage Lossesi R Loadi A Load i (5) (4) Southern California Edison Chapter 12, Page 13

16 12.10.A. Definition of Imbalance Energy (IE) Imbalance Energy represents the generation or demand the ISO must dispatch from generation or loads to meet generation and demand imbalances to insure grid reliability. For each Scheduling Coordinator, Imbalance Energy is equal to that Scheduling Coordinator s Actual Imbalance plus its ISO allocated share of UFE, as shown below for Scheduling Coordinator i: IESCi = AISCi + UFESCi (6) B. Definition of Actual Imbalance (AI) Actual Imbalance is defined as the deviation at the UDC/ISO interface boundary between scheduled generation and metered generation minus the deviation between scheduled load and metered load. AI represents either the excess or deficit of energy actually provided by the SC compared to what was scheduled. AI is illustrated by the following formula 3 : AI SCi = (total scheduled generation - total actual generation) - (total scheduled load - total actual load) (7) C. Definition of UFE UFE represents the difference between the energy entering a UDC at the ISO/UDC interface minus the total UDC metered demand. More specifically, UFE is calculated by the ISO as the difference between the net energy into a specific UDC service area, adjusted for UDC service-area Transmission Losses and local generation, minus the total UDC metered load (settlement ready data with all distribution system demand adjusted by DLFs). The ISO Tariff definition of UFE attributes the above calculated difference to the combination of: a) DLL deviations (corresponding to DLF deviations), b) meter errors, c) energy theft and d) statistical load profile errors. This definition is consistent with the DLFDLL methodology. If the DLFTDL methodology is used, the ISO calculated difference described above would be attributable to a combination of a) deviations in DLL, b) deviations in meter error, c) deviations in energy theft and d) statistical load profile errors. The effects on UFE of the two DLF methodologies are described in the following sections C.1 Definition UFEDLL - DLFs Correspond to Distribution Line Losses Only As shown in Section 2.1, in the case where the DLFs correspond to the distribution system line losses only, the 3 The scheduled generation and actual generation will have Generator Meter Multipliers (GMMs) applied to account for transmission system level losses. Southern California Edison Chapter 12, Page 14

17 relationship between the DLFDLL and the line losses is given by equation (2). This particular representation of DLFs is adopted by the ISO Tariff. This is shown in equation form as: UFE DLL = Distribution line loss deviation + Meter error + Energy theft + Load profile deviation (8) = (DLL dev) + (ME actual) + (T actual) + (LP dev) C.2 UFETDL - DLFs Correspond to Distribution Line Losses, Meter Error, and Energy Theft As shown in Section 2.1, in the case where the DLFs correspond to the aggregation of distribution system line losses, energy theft and meter error; the relationship between the DLF and these losses is given by equation (3). Here the UFE calculation would represent the deviation in the aggregate estimate of DLL, meter error and energy theft, together with the deviation in the statistical load profile estimate. UFETDL can then be represented as follows: UFE TDL = (Distribution line loss + Meter error + Energy theft) deviation + Load profile deviation (9) = (DLL + ME + T) dev + (LP dev) C.3 Comparison of UFE Formulae The primary difference between the two UFE formulae (UFEDLL and UFETDL) involves the treatment of meter error and energy theft. Under the first, the actual amounts of meter error and energy theft are included in UFE, whereas in the second, meter error and energy theft are included as a single component in system loss and thus, UFE includes only the deviations between these estimates and their actual amounts. Because the ISO calculation of UFE is independent of which DLF methodology is used, the deviations between actual losses in the UDC distribution system and the UDC system losses that are accounted for in the DLFs are implicitly picked up as part of the UFE calculation. Thus, where meter error and energy theft are included into DLFs (DLFTDL), the calculated UFE will tend to be slightly smaller, as compared to where DLFs represent distribution line losses only (DLFDLL). These alternative definitions of DLFs and corresponding UFE are illustrated in Figure 2. Southern California Edison Chapter 12, Page 15

18 ISO Tariff Energy Measurement at ISO/UDC Grid Interface Alternative LP dev LP dev UFE DLL ME actual UFE TDL (DLL+ME+T) dev T actual E DLL DLL dev Est. DLL Actual DLL E TDL Est. (DLL+ME+T) E dist Energy Measurement at End-use Meter E dist Energy Measurement at End-use Meter DLF DLL DLF TDL Figure 2: Comparison of DLFs and UFEs C.4 Allocation of UFE Each Scheduling Coordinator s share of UFE will be allocated based on the ratio of the Scheduling Coordinator s demand (interval metered and estimated using load profiles) within the UDC service area to total demand within the UDC service area (regardless of which type of DLF is applied). The ISO Tariff states that UFE calculations and allocations will be made on a best-estimate basis, using a methodology approved by the ISO Governing Board. To the extent possible, UFE associated with load profiling error will be allocated only to demand where load profiles have been applied D.5 DLF Effects on Imbalance Energy ISO calculated Imbalance Energy is affected by the implicit effects of DLFs in its individual components. As discussed above, depending on the DLFs used, the UFE may be expected to be higher or lower depending on the UDC service area. Since the DLFs are known, Scheduling Coordinators may adjust their AI by increasing or decreasing their schedules (energy procurement) in the day ahead market, to minimize their share of Imbalance Energy. For example, where DLFs represent distribution line losses only, Scheduling Coordinators who wish to minimize Imbalance Energy, may choose to slightly increase their schedules (i.e., Southern California Edison Chapter 12, Page 16

19 12.11 DLF Data Communication Proposal procure more energy) to compensate for UFE associated with meter error and energy theft. This section suggests the protocols and procedures for the communication of the DLFs to those market entities who need it (primarily ESPs). Each UDC will utilize this same set of protocols and procedures. The format stated in Section 5.7 of this report will be the format that will used for the communication of the DLFs and supersedes the format suggested in the UDC-ESP Communications Report Supplement to the RSIF, dated August 18, A Assumptions and Allowances The following assumptions apply to this information flow proposal. If any of the assumptions/allowances are invalid, no warranty is made on any aspects of the proposal that were based on the invalid assumptions/allowances. The protocols and procedures listed in this section: allow for one set of DLFs (assuming the DLFs will be dynamic); and assume that the data needed to determine the DLFs will be available within the set time frames listed so that the DLFs can be made available in time to meet market requirements B Protocols for Communication - A Starting Point The proposed starting point for the posting of DLFs is the examination of the protocols and procedures setup for the generic meter data management agent (MDMA). The MDMA protocols were developed through the MADAWG 4 process and have been included into the Meter Data and Communications Standards Workshop Report. MDMA functions include the following: collect meter data, validate, estimate and edit meter data, manage meter data (e.g., data storage), disseminate meter data, and ensure the security of the meter data. The application of distribution loss factors to metered data is not one of the minimal requirements, nor does this set of requirements prohibit this application from being performed at the MDMA level. In disseminating and ensuring the security of meter data, various protocols were established. These protocols represent minimal requirements that must be established by the MDMA. To summarize: B.1 MDMA Communication Protocols: meter data will be posted on a data server (logically directory based); authorized entities will dial-in to the server; 4 Meter And Data Access Working Group Southern California Edison Chapter 12, Page 17

20 data will be retrieved in a pre-defined file format; the data transfer protocol will be HyperText Transfer Protocol on top of TCP/IP, with Secure Sockets Layer added for data security (encryption); and the transport medium will be the Internet. (This actually makes the server a Web server) B.3 MDMA Security Protocols: all parties accessing data must have an user id and password; and only data authorized to an entity will be accessible by that entity C Distribution Loss Factors Communication It is recommended that the communication of DLFs follow in a similar manner the protocols and procedures setup for the generic MDMA. In other words, all the protocols and procedures used for the MDMA will also be used for the DLF communication. The reasons for this are: C.1 all three UDCs are already implementing these basic protocols and procedures for their own MDMA function; and C.2 the communication of the DLFs is basically similar to that of the meter data and thus the use of the MDMA protocols and procedures seems appropriate. However, because the DLFs are not proprietary and are for public viewing, the security restrictions can be relaxed. Therefore, the five communication protocols listed above will be adopted for the DLF communication standards with security relaxation in protocols 2 and 4. The DLF communication protocols at a minimum must include: C.3 DLF Communication Protocols: DLF data will be posted on a data server (logically directory based); entities will dial-in to the server; data will be retrieved in a pre-defined file format; the data transfer protocol will be HyperText Transfer Protocol on top of TCP/IP (see Section 5.4); and the transport medium will be the Internet. (This does not prohibit the use of other types of transport mediums such as WEnet) D Accessing the Distribution Loss Factors Since HTTP is the transfer protocol and the system is logically a commercial Web server platform, general Web-based services can be utilized to obtain the DLFs. At a minimum, the data should be accessible through two methods: Southern California Edison Chapter 12, Page 18

21 a Web browser, such as the Internet Explorer or Netscape; and a command line driven program/script. (This will accommodate an automated process). Each UDC will provide the address (IP number) of the server upon which these DLFs will be posted E. File Structure and Filenames The proposed file structure convention will be the following: E.1 there will be one file for DLFs; E.2 one day s set of DLFs will reside in an individual file; E.3 the filename will reflect the date of the day for which these DLFs correspond; and E.4 there will be one yearly file that holds all DLF data up to the current time. The proposed file naming convention is the following: For the daily file, the name will be: fccyymmdd.dlf: This is the file name for the daily DLFs file. The ccyymmdd stands for century, year, month and day. An example would be f dlf. For the yearly file, the name will be: fccyy.dlf: This the file name for the yearly accumulated DLFs file. The ccyy stands for century and year. An example would be f1998.dlf F. Timing and File Availability The primary purpose of the DLFs is to provide guidance for forecasting/scheduling load and the application to the actual meter data for settlement with the ISO. Since forecasting/scheduling load must be completed early the day before the trading day, the DLFs must be posted before this. Therefore, the DLFs will be posted shortly after the UDCs provide the UDC demand bid to the PX (the DLFs are based on the internal UDC system load forecast) and before the Scheduling Coordinators are required to provide their preferred schedule in the day prior to the trading day. Since the meter data does not need to be submitted to the ISO until 41 (PX until 38) days after the trading day, it must stay posted for 42 days. The yearly accumulating DLF file will be posted for at least one more year G. Data Format The format of the DLF file (both daily and yearly) will be a sequence of ASCII text lines, terminated with ASCII carriage return characters. Southern California Edison Chapter 12, Page 19

22 Each text line in the file will consist of a series of free format fields with individual fields comma delimited. Each text line has the form: record/version type, UDC name, date/hour, DLF type, subtransmission voltage DLF, primary voltage DLF, secondary voltage DLF where, the each field has the following definition: G.1 record/version type The record/version type for this record. This field is 6 characters long and must start at the beginning of this text line. The first 3 characters must be DLF and the next three characters represent the record type version number (e.g., 001) G.2 UDC name The name of the UDC for which these factors correspond. This field must not exceed 16 characters and the UDC names will be those used in the California Metering Exchange Protocol G.3 date/hour The date/hour for which these factors correspond. The date/hour format is CCYYMMDDHH. CCYYMMDDHH stands for century, year, month, day and hour, e.g., The date/hour must be provided in Universal Coordinated Time 5 (UTC) with the minute component absent. The hour (HH) component is a two digit integer in the sequence, 00, 01,..., 22, 23. The hour component will represent the start of the hourly period, e.g., HH = 01 represents the hour from 1:00 AM to 2:00 AM (GMT) and HH = 23, the hour from 11:00 PM to 12:00 AM (GMT) G.4 DLF type The default key character is F G.5 DLFs The DLF values will be real numbers and will be in floating point notation. The subtransmission voltage DLF in the fourth field, the primary voltage DLF in the fifth field and the secondary voltage DLF in the sixth (last) field. If a given UDC does not have one of the voltage level types listed, the field will be empty. The following is a partial example of a daily DLF file from a UDC for May 22 nd, 1998 for 3:00 AM Pacific Daylight Time. DLF001, UDCNAME, , F,, 1.041, For this example, this UDC does not have subtransmission voltage DLFs so this field is left blank. Also, the Pacific Daylight Time is converted to UTC time (in this case adding 7 hours). 5 In practice UTC is the same as Greenwich Mean Time (GMT), i.e., the local time at the Greenwich meridian (zero degrees longitude). Southern California Edison Chapter 12, Page 20