Distribution System EE Methodology

The general methodology for all energy efficiency measures can be found here. The sections below provide an overview specific to the utility distribution system sector.

Overview of Methods for Distribution System Sector

Measure cost and savings assumptions are based on engineering analysis, the 2007 study by Leidos (formerly RW Beck) for the NEEA Distribution System Initiative, and input from distribution system engineers at Bonneville, regional utilities, and national experts. The savings methodology hinges on estimates of utility loads, substation count, feeder count, and other characteristics of the distribution system and end user load. These data are largely from utility-specific EIA 2018 sales data augmented by Bonneville and utility data where gaps exist. Measure applicability factors are largely from interviews with larger public and private utilities. Where gaps exist, the analysis relies on expert judgment.

Savings are ultimately based on estimates of energy saved relative to voltage change referred to as the Conservation Voltage Reduction factor (CVRf). Three Energy Conservation Measures (ECMs) are used to estimate increasing levels of voltage reduction, and savings, across the feeders. The CVRfs for each utility system are then modified to account for effectiveness of the voltage reduction on savings based on estimated mix of inductive versus resistive loads, the rural versus urban mix of feeders, and the average climate zone for each utility.

For the 2021 Plan, cost estimates were revised after consultation with Bonneville staff. The updated cost estimates are separated into capital expenditures and operations and maintenance costs. Cost elements include engineering, telemetry and control equipment, testing, and software. Costs are applied per utility, per substation, and per feeder depending on the ECM and the distribution system configuration of each of the 146 utility distribution systems.  

Physical Units for Distribution System

The conservation supply curves are developed by identifying the physical characteristics of regional distribution systems, operating conditions such as baseline substation and feeder voltage, and the loads served. The assessment incudes estimate of substation count, feeder count, energy sales, and type of load for 146 utility-specific distribution systems. This includes characterization of the urban versus rural geography, climate zone, inductive versus resistive load, and distribution of residential, commercial and industrial sales of kWh. A mix of data sources are used to generate the physical units for existing distribution systems including EIA form 861, RTF climate zone data, and Bonneville and utility interviews. The Council load forecast is used to estimate savings from system expansion. The Council estimates that there are 2215 distribution substations and over 4200 urban and rural feeders in the region.

Baseline Characteristics for Distribution System

Baseline conditions for voltage and distribution system configuration were estimated from the NEEA study and discussions with Bonneville and utility staff.

Measure Applicability and Achievability

Estimates of CVR already completed are from utility interviews. Presence of Automatic Meter Infrastructure (AMI) are from EIA data, utility interviews and expert judgment. Expert judgment also informs the relative applicability of the three ECMs across systems and residential versus commercial and industrial load. Achievability ramp rates are slow based on past experience and the expected roll out schedule of AMI throughout the region.

Guide to Workbooks

A single workbook contains all the data and analysis. The workbook is downloadable. The table below describes the key worksheets and their functionality.