Transcript Slide 1

Cost Effectiveness and Rate Making
GRIDSCHOOL 2010
MARCH 8-12, 2010  RICHMOND, VIRGINIA
INSTITUTE OF PUBLIC UTILITIES
ARGONNE NATIONAL LABORATORY
Rick Hornby
Synapse Energy Economics
[email protected]  617 661 3248
Do not cite or distribute without permission
MICHIGAN STATE UNIVERSITY
Introduction
Proposed investments in smart meter infrastructure (SMI) typically represent major
increases in the revenue requirements of distribution utilities, leading to requests for
increases in rates for distribution service. When determining whether to approve such
requests, utility regulators consider several standard ratemaking issues. This session
will address the following ratemaking issues associated with such proposals:
i.
Cost effectiveness. What tests do regulators consider when determining
whether proposed investments are cost effective? What are the key inputs to
those tests? What is the role of benchmarking and scenario analyses?
ii. Rate Making – What are rate implications for consumers?
a. Rate Mechanisms. What rate mechanisms can utilities use to recover the
investment in SMI, and their relative advantages and disadvantages?
b. Cost Allocation. What ratemaking principles apply to the allocation of SMI
revenue requirements among rate classes?
c. Rate Design. What ratemaking principles apply to the design of rates to
collect SMI revenue requirements.
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I. Cost - Effectiveness
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I. Cost - Effectiveness
SMI projects typically have six major components
1.
2.
3.
4.
5.
6.
In Home Technologies, such as displays and programmable controllable thermostats (PCTs)
Smart meters
Communication network
Back Office Systems, including a Meter Data Management System (MDMS)
Customer interface
System management and security
One high level approach to determine whether these costs are reasonable is to benchmark them
against the costs of SMI projects of other utilities.
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I. Cost - Effectiveness
Capital Costs of Smart Meter Infrastructure Projects Expressed in $ per installed meter
700
600
Total $/installed meter
500
Back Office, Customer
Interface & Security
400
Communication
Network
300
Meters (installed)
200
100
0
Oncor
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Centerpoint
SCE
SDG&E
PEPCO
DPL MD
BGE
AP
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I. Cost - Effectiveness
 Many regulators apply the Total Resource Cost test (TRC) to determine whether a
proposed investment is cost effective.
 The TRC test compares, over the life of the investment, the net present value (NPV) of all
projected costs associated with the investment, regardless of who pays them, with the
NPV of all projected benefits from the investment, regardless of who receives them. (A
common discount rate used in the NPV is the utility’s weighted average cost of capital.)
 A proposed investment is cost effective under the TRC if the NPV of its projected benefits
exceeds the NPV of its projected costs. This relationship is often expressed as a benefit
to cost ratio, where a ratio greater than 1 indicates the investment is cost-effective.
 A b/c ratio much higher than 1 is preferable, as this indicates a project with “robust”
economics. This is important because of the uncertainty associated with projecting costs
and benefits.
 A related approach to testing cost effectiveness is to test the sensitivity of the b/c ratio to a
change in input assumptions. This is referred to as a sensitivity or a scenario analysis.
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I. Cost - Effectiveness
 Major categories of projected savings from investments in SMI.
 projected savings in distribution service costs due to SMI alone:
 Reductions in annual operation and maintenance expenses, primarily meter reading
but also meter operations and revenue protection
 Avoided capital expenditures in “business as usual” meters and IT
 projected savings in distribution service costs due to SMI plus dynamic pricing
 Avoided distribution service capacity costs due to reductions in demand
 projected savings in electricity supply costs
 Avoided generation capacity costs due to DR in response to dynamic pricing (DP)
 Lower generation capacity costs from lower capacity prices due to DR from DP
 Avoided generation energy costs due to EE in response to feedback
 Lower generation energy costs from lower energy prices due to EE from feedback
 Other benefits are often mentioned but rarely quantified. These include reductions in
emissions of greenhouse gases (GHG), improved reliability of distribution service,
enabling of plug-in hybrid electric vehicles (PHEV) and enabling of distributed generation.
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I. Cost - Effectiveness
BGE Smart Grid Initiative
Business Case Projected Total Costs and Benefits (NPV)
$1,400
Capacity Revenues & Price Mitigation
Energy Revenues and Price Mitigation
$1,200
Avoided T&D Capital
Energy Conservation
$1,000
Avoided Meter Related Capital
64% of Total Benefits
depend on response to
PTR
Distribution O&M Savings
$800
Total Costs
$600
AMI Benefits alone do
not justify Initiative
$400
15% of Total Benefits from
Energy Conservation
$200
21% of Total Benefits are
AMI related
$Costs
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Benefits- AMI Only
Benefits - AMI + SEP (Business
Case)
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I. Cost - Effectiveness
 Investments in SMI typically have to justified based upon projected savings in distribution
service costs plus projected savings in electricity supply costs.
 The need for both categories of savings can pose a problem for “Distribution Service” only
utilities, who have no control over rates for supply service.
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I. Cost Effectiveness
Illustrative Residential Monthly Bills for 1,000 kwh
$160.00
$140.00
$120.00
$100.00
Supply
Distribution
$80.00
$60.00
$40.00
$20.00
$-
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Utility A
Utility B
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I. Cost - Effectiveness
 The fact that projected savings in distribution service capacity costs, and all of the
projected savings in electricity supply costs, hinge upon assumptions regarding customer
sustained response to prices and feedback is a source of substantial uncertainty since
there is limited empirical evidence regarding that response.
 It is helpful to determine how sensitive the cost effectiveness of a proposed
investment is to changes in input assumptions.
 Not every proposed SMI is cost-effective.
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I. Cost - Effectiveness
BGE Smart Grid Initiative
Projected Total Costs, Projected Total Benefits Business Case and Projected Total Benefits
Low PTR Participation/low capacity Value/low energy conservation case(NPV)
$1,400
Capacity Revenues & Price Mitigation
Energy Revenues and Price Mitigation
$1,200
Avoided T&D Capital
Energy Conservation
$1,000
Avoided Meter Related Capital
Distribution O&M Savings
$800
Total Costs
$600
$400
AMI benefits are 37% of Total
Benefits in the low PTR
participation + low capacity value
+ low energy conservation
$200
$Costs
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Benefits - AMI + SEP (Business Benefits - low PTR Participation
Case)
+ low Capacity Value + low
Energy Conservation
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I. Cost - Effectiveness
Allegheny Smart Meter Plan – Projected Total Costs and Benefits ($ million NPV)
$700.00
$600.00
DR - Other Programs and Rates
DR - C&I Customer Load
Response & DG
Distribution Service Savings
$500.00
CIS (incl O&M)
$400.00
In Home Devices (installed)
Network + Other Installation + IT
+ O&M
Meter Cost (Installed)
$300.00
$200.00
$100.00
$Costs
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Benefits - Distribution
Service Savings
Benefits - Distribution
Savings + Demand
Response
Benefits - Distribution
Savings + Demand
Response ($40 per kwhyr)
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II. Rate Making -What are the rate implications for mass
market consumers?
 Investments in SMI that are cost-effective will still typically result in requests for increases
in rates for distribution service.
 The level of these increases, and the design of the distribution service rates set to collect
them, will affect the attitudes of mass market consumers towards smart meters.
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II. Rate Making -What are the rate implications for mass
market consumers?
BGE Smart Grid Initiative
Proposed Mechanisms for Cost Recovery and Crediting Benefits
$1,400
Energy Conservation
PTR and conservation
benefits only flow to
ratepayers who
participate
$1,200
$1,000
Peak Time rebate - Capacity and
energy Revenues
Standard Offer Service - Energy and
Capacity Price Mitigation
Base Rates - Other Distribution
savings
SGC - Meter reading O&M savings
$800
SGC collects 100% of costs but
credits only small % of benefits
SGC - Total Costs
$600
Need new
base rates to
reflect these
benefits
$400
$200
$Costs
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Benefits - AMI + SEP (Business Benefits - low PTR Participation
Case)
+ low Capacity Value + low
Energy Conservation
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II. Ratemaking - Rate Mechanisms
 Base rates are the traditional mechanisms through which utilities recover all of their costs,
including return of and on investments such as SMI. Base rates are set in general rate
cases which typically only occur every few years
 Advantages. Regulator and all parties have ample time to thoroughly review projected costs
and savings. Projected savings in distribution service costs can be reflected in rates. Utility
bears financial risk if its actual net costs are greater than revenues it collects from base rates.
 Disadvantage. General rate cases are expensive and time consuming
 Utilities often request permission to recover the costs of their investment in smart meters
through fully reconcilable surcharges which would be reset every year, if not more often.
 Advantages. Utility has greater assurance of recovering costs. Utility can pass savings through
to customers as they occur.
 Disadvantages. Regulator and all parties may have less time to review costs and savings.
Level of savings credited to customers may be less than projected. Ratepayers bear financial
risk if actual net costs are greater than projected.
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II. Rate Making -What are the rate implications for
consumers?
Potomac Electric Power Company - Maryland
AMI Implementation
No DOE Funding
Estimated Trend of Monthly Incremental Customer Bill Impacts
$6.00
$5.00
Deferred Cost Recovery
Existing Meter Recovery
$4.00
AMI Cost
Supply-Related Benefits
$3.00
AMI Operational Benefits
$2.00
$4.21 $4.08 $3.92
$3.51
$1.00
Net of Cost /Operational and
Supply Benefits
Net of Cost/Operational Benefit
$3.12 $2.95 $2.82
$2.75 $2.55 $2.40
$2.23 $2.05
$1.86 $1.64
$0.82
$$(1.20)
$(1.00)
$(2.00)
$(1.61) $(1.65) $(1.68) $(1.72) $(1.76) $(1.80) $(1.84) $(1.89) $(1.93)
$(1.98) $(2.02) $(2.07) $(2.12) $(2.17)
$(1.94)
$(3.00)
$(3.60) $(3.38)
$(2.81) $(2.90) $(2.99)
$(3.08) $(3.17)
$(4.45)
$(4.00)
$(3.27) $(3.36)
$(3.46) $(3.56)
$(3.67) $(3.78)
$(5.00)
$(6.00)
$(7.00)
$(8.00)
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
Full Service Year
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II. Ratemaking - Allocation of Costs among Rate Classes
 According to generally accepted ratemaking principles, costs should be allocated among
rate classes according to cost causation.
 Analysts can, and do, disagree over the factors that “cause” certain categories of costs.
SMI costs are one such category.
 What factor(s) “cause” a utility to incur SMI costs - number of customers, demand, energy,
or some combination of those three? The answer to this question has very different
implications for mass market customers, as indicated below for an illustrative utility.
Rate Classes
Residential & small C & I
Medium and Large C & I
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Allocation Factors
# Customers
Peak Demand
98.2%
68.7%
1.8%
31.3%
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IV. Ratemaking - Rate Design
 Distribution utilities collect their revenues through three basic types of rates - a customer
charge $/month), a demand charge ($ per kW per month), or an energy or delivery charge
($/kWh). Most tariffs for mass market customers only have customer charges and energy
charges.
 According to general ratemaking principles, after the amount of revenues to be collected
from a particular rate class has been determined, the decision regarding the portion of the
rate class revenue requirement to recover via the customer charge and the portion to
recover via the delivery and/or demand charge should be based upon the results of a costof-service study plus an analysis of bill impacts. Ratemaking principles call for the exercise
of judgment when determining the level of increase in each type of rate in order to avoid
too sharp an increase.
 The customer charge can represent a significant portion of the monthly bill of mass market
customers.
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IV. Ratemaking - Rate Design
Impact after ARRA Smart Grid Investment Grant Change in Residential Annual Bills in 2012 from a Smart Grid Customer Charge before any
offsetting savings from participation in PTR or Energy Conservation
$15
$10
3.0% explicit
increase
1.9% explicit
increase
1.4% explicit
increase
0.8% explicit
increase
$5
Supply Price Mitigation at ($0.00086) per kWh
$0
Net Operational Cost + existing Meters at $1.17 per
meter per month
-$5
-$10
-$15
220 kWh/month
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380 kWh/month
530 kWh/month
946 kWh/month
(average)
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Contact
Synapse Energy Economics
617 661 3248
www.synapse-energy.com
Rick Hornby (ext 243)
[email protected]
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