Download Introduction to Efficient Pricing

Introduction to Efficient Pricing
Presented to:
Edison Electric Institute’s Advanced Rates Course
University of Wisconsin, Madison
Presented by:
Philip Q Hanser
July 23, 2012
Copyright © 2012 The Brattle Group, Inc.
www.brattle.com
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What Do We Mean by Efficient Pricing?
In the economists (and engineer’s) view of the world, prices
are efficient is they provide the right signals to customers
about the costs of the goods they purchase, i.e.,
♦ IF IT COSTS MORE TO PRODUCE, IT’S PRICE IS HIGHER.
In the utility world, this gets somewhat confused because rate
of return regulation results in costs, which can be dominated
by the history of investments the utility has made, i.e.,
♦ Accounting costs ≠ actual production costs necessarily
Marginal costs represent the true opportunity cost to the
utility and should be reflected (notice term!) in rates.
2
Why Marginal Cost-Based Rates?
♦ Rates reflecting marginal costs mimic the presumed
structure of prices in competitive markets, thus should be
efficient prices
♦ Typical rates are usually only remotely reflective of the
true cost to serve customers
• Embedded cost-based rates have averaged into them the entire
history of investments by utility
■ Is the cost of laying new conductor in downtown areas the
same as that when the lines were originally constructed?
♦ All true costs are opportunity costs, avoids the fallacy of
sunk costs
FUNDAMENTAL QUESTION: What costs do you incur as a utility in
providing an additional unit of service to a customer or to serve
an additional customer at a specific time and location?
3
Some Market Organization Background
Just as the ancients believed that the world is composed of
four elements – Earth, Wind, Fire, and Water.
All of Rate Design is composed of four elements –
Generation, Transmission, Distribution, and Customers.
However, the electric utility combines these four elements
differently depending on whether your utility is integrated
or not, whether it is in a regional transmission organization
(RTO) or not, and if it is in an RTO, how the RTO is
organized.
4
Traditional Markets
♦ Traditional Markets
• Comprised of primarily integrated utilities
• Price formation is entirely through regulation by public utility
commissions.
♦ Utility performs the following functions
• Distribution
 Low voltage wires providing service to ultimate customer –
residential, commercial, small industrial
• Transmission
 Bulk power system
♦ Provides “highway” connecting generation to distribution system
♦ Largest customers connect at the voltage levels of transmission system
♦ Interconnection to other utilities provides reliability enhancement and
potential for economic interchange
• Generation
 Owned by utility
 Economic dispatch
5
Traditional Markets
Utility B
Utility A
Generator
Generator
Wholesaler/Transmitter
Wholesaler/Transmitter
Distributor
Distributor
Customer
Customer
Decentralized Bilateral Trade
6
Three Primary Generation Types
1. Baseload
• High capital costs, low marginal energy costs

Coal, nuclear
2. Intermediate
• Capital costs lower than baseload, but higher marginal energy
costs
• Usually fairly flexible in varying output levels
 Combined cycle gas turbine (CCGT) is typical unit
3. Peaking
• Low capital costs and short lead times to build
• High marginal energy costs
 Natural gas combustion turbine (CT) is typical unit
7
Other Generation
♦ Large scale hydroelectric
• Big dams
• 000’s MW
• Pondage provides storage
♦ Smaller scale hydroelectric
• Run-of-river
• Typically small MW’s – a few to 100
♦ Biomass – waste-to-energy – primarily co-generators selling power to
utility
♦ Renewable resources
• Typically characterized as high capital costs, but very low marginal
energy costs, sometimes zero
• Characterized by intermittency of output
 Predictable, but largely controllable
 Geographic-specific
 Wind, solar thermal, solar PV
8
Restructured Markets - Wholesale
♦ Restructured Markets – Regional transmission organizations (RTOs)
• Aggregated transmission system operated by independent system operator
(ISO) whose primary function is to provide open access to the transmission
system and balance supply and demand
 Utilities retain TX ownership, requirement for maintenance, expansion
 Federal Energy Regulatory Commission (FERC) sets RTO’s rate and regulates
• Generation bid into market
 Some utilities have retained generation ownership
 New entrants
 Very loosely regulated by FERC
• Residual traditional utility, now known as Load-Serving Entity (LSE) or Local
Distribution Company (LDC), operates and maintains the wires to retail customers
 Under wholesale competition
♦ Retains supplier role, purchasing on behalf of customers
 Under retail competition
♦ Residual obligations, Provider of Last Resort (POLR)
 In both approaches, regulated by state public utility commissions
9
Restructured Markets - Wholesale
Wholesale competition - Centralized Market Design
Genco
Genco
Genco
Genco
Genco
ISO Wholesale Market
Regional Transmission Organization
LSE
Consumers
LSE
LSE
Consumers
Consumers
10
Large
customer
Restructured Markets - Wholesale
Centralized Wholesale Market/Decentralized Retail Market
Genco
Genco
Genco
Genco
Genco
ISO Wholesale Market
Regional Transmission Organization
Retailer
Retailer
Retailer
Large
customer
Retail market
LSEs
Consumer
Consumer
Consumer
11
Consumer
Restructured Wholesale Market
♦ ISOs are also market-makers
♦ Multi-settlement market
• Day-ahead hourly market (DAM) – Locational Marginal Prices (LMPs)
calculated
 Originally, these were called Locational Marginal Cost prices.
• Real-time
 Real-time LMPs calculated
 Deviations from generation schedules (unscheduled outages)
 Deviations from forecasted bids or demand
• Day-after
 Generators paid based on schedule, LSEs pay based on projected or bid
demands
 Suppliers and demanders charged for increased costs resulting from deviations
from schedule by settling at real time prices
♦ Ancillary services markets
• Operating reserves
• Transmission-related
 VARs
• Capacity/Forward reserves market
12
The Logic of Dispatch Units
Excess Capacity
Demand Spike
Demand
$ / MW
$ / MW
Demand
Supply
Supply
MW
MW
13
Locational Marginal Prices Across a Day
Locational Marginal Prices on August 1, 2002
NY City-PJM-Cinergy
180
NY City
Cinergy
160
Central NY
140
Prices ($/MWh)
120
100
80
60
40
20
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Hour
Source: New York ISO and Intercontinental Exchange
14
Cost Element
Centralized
Restructured
Traditional
Decentralized
Restructured
Utility supplies both energy
and capacity. Investments
and O&M are included in
revenue requirements.
RTO market provides energy
and capacity. Investments
and O&M are included in
requirements, but netted
against sales/purchases in
RTO.
Market provides both energy
and capacity. Either
generation costs from
market are passed through
or utility contracts on behalf
of customer (POLR, etc.)
Utility supplies transmission
services. Investments and
O&M are included in revenue
requirements.
RTO supplies network
transmission services. As
with generation, investments
and O&M are included in
revenue requirements, but
netted against
sales/purchases in RTO.
RTO supplies network
transmission services. Costs
are passed through to
customers.
Distribution
Utility supplies distribution
services. Investments and
O&M are included in revenue
requirements.
Utility supplies distribution
services. Investments and
O&M are included in revenue
requirements.
Utility supplies distribution
services. Investments and
O&M are included in
revenue requirements.
Customer
Metering, customer services,
connections, etc. supplied by
utility. Investments and
O&M are included in revenue
requirements.
Metering, customer services,
connections, etc. supplied by
utility. Investments and O&M
are included in revenue
requirements.
Metering, customer services,
connections, etc. supplied
by utility. Investments and
O&M are included in
revenue requirements.
Production
(Generation)
Transmission
15
Steps in Developing Marginal Cost-Based Rates
1. Carrying charges – annualizing investments
2. Marginal Generation Costs
Marginal generation capacity costs
b) Marginal generation energy costs
Marginal Transmission Capacity Costs
Marginal Distribution Costs
a) Marginal distribution customer-related costs
b) Marginal distribution capacity-(demand)-related costs
Determine appropriate costing periods
Attributing costs to costing periods
Adjustment of marginal costs for losses
Reconciling marginal cost-based rates with revenue
requirements
a)
3.
4.
5.
6.
7.
8.
16
Steps in Developing Marginal Cost-Based Rates
1. Carrying charges – annualizing investments
2. Marginal Generation Costs
Marginal generation capacity costs
b) Marginal generation energy costs
Marginal Transmission Capacity Costs
Marginal Distribution Costs
a) Marginal distribution customer-related costs
b) Marginal distribution capacity-(demand)-related costs
Determine appropriate costing periods
Attributing costs to costing periods
Adjustment of marginal costs for losses
Reconciling marginal cost-based rates with revenue
requirements
a)
3.
4.
5.
6.
7.
8.
17
1. Carrying Charges – Annualizing Investments
The capacity costs — generation, transmission, distribution
and the customer costs — represent investments made by
the utility over a particular time span, say one to several
years, but whose lives are considerably longer, say 15 to 30
years. Converting those lumpy investments into annual
costs is called annualization.
Two kinds of carrying charges
♦ Levelized (nominal)
♦ Economic (real)
18
1. Illustration of Alternative Carrying Charges
For purposes of these examples assume
♦ Weighted average incremental cost of capital = 12%
• Inflation rate =
6%
• Investment life = 30 years
♦ Present value of revenue requirements per dollar of
investment = 1.3, i.e., a $1 investment has a PVRR of
$1.30
19
1. Illustration of Alternative Carrying Charges
Assumptions:
♦ r = the weighted average incremental capital cost = 12%
♦ e = the rate of inflation = 6%
♦ N = the book life of the investment = 30 years
♦ I = the initial investment cost = $1.00
♦ K = the present value of revenue requirements = 1.3 x I.
Capital Recovery Factor:
♦
= Ir
(1+r)n
= .1241 or 12.41%
(1+r)n-1
Levelized Carrying Charge:
♦
= Kr
(1+r)n
= .1641 or 16.14%
(1+r)n-1
(or = 1.3 x .1241)
Economic Carrying Charge:
♦
= K(r-e)
(1+r)n
= .0965 or 9.65%
(1+r)n - (1+e)n
20
1. Comparison of Carrying Charges in Nominal
Dollars
Economic
Carrying
Charge
$
Revenue
Requirement
Levelized
Carrying
Charge
0
10
20
21
30
Years
1. Comparison of Carrying Charges in Constant
Dollars
Revenue
Requirement
$
Economic
Carrying
Charge
Levelized
Carrying
Charge
0
10
20
22
30
Years
Steps in Developing Marginal Cost-Based Rates
1. Carrying charges – annualizing investments
2. Marginal Generation Costs
a) Marginal generation capacity costs
b) Marginal generation energy costs
3. Marginal Transmission Capacity Costs
4. Marginal Distribution Costs
a) Marginal distribution customer-related costs
b) Marginal distribution capacity-(demand)-related costs
5. Determine appropriate costing periods
6. Attributing costs to costing periods
7. Adjustment of marginal costs for losses
8. Reconciling marginal cost-based rates with revenue
requirements
23
2. Marginal Generation Costs – Marginal Generation
Capacity Costs
If in a regional transmission organization (RTO), easy – either penalty for failing to have adequate
capacity or price set in capacity market; if not in an RTO, need to answer the question:
♦ If demand increased a non-trivial amount, say 50 MW, how would the utility respond in the most
economic manner while maintaining the same level of reliability?
Load (MW)
1 KW
1,000
MC = cost/kW (1000/500) RM
0.5 KW
500
Hours
24
7,000
8,760
2. Marginal Generation Costs – Marginal Generation
Capacity Costs (cont’d)
Two primary approaches:
♦ So-called NERA peaker method
• A combustion turbine has low capital costs, although its fuel
efficiency is relatively low
• CT on a flatbed
♦ System planning approach
• What is the least cost adjustment to planned capacity additions
needed to meet the increase in load and maintain the same
reliability?
■ How would the system planner respond to the change in load?
■ How would the resource plan change?
♦
♦
Move up the schedule of planned resource additions
Add new resources
25
2. Marginal Generation Costs – Marginal Generation
Capacity Costs (cont’d)
System planning method steps
1. Determine planned response to a change in forecast load growth
2. Determine capacity cost per kilowatt of response
3. Annualize the capacity costs
4. Add the O&M per kW
5. Compute and deduct any fuel or other savings per kW
6. Adjust for reserve margin; ancillary services, etc.
An aside on measures of reliability
♦ Loss of load probability (LOLP) – Probability that load exceeds
resource capability
♦ Loss of energy probability (LOEP) – Percent of energy that will be
unable to meet with current resource capability
• LOLP as a reliability is appropriate only when marginal outage cost
does not vary with the magnitude of the shortages.
26
Marginal Capacity Costs Using the System Planning
Method: Planner Builds Combustion Turbine
Minimum Capacity Required:
Requirement Met By:
60 MW
Building a combustion
turbine
Marginal Cost
Annualized Cost of a Turbine (2012$): $58/kW (580 x 10%)
Fixed O&M:
$2/kW
Reserve Margin:
20%
Adjusted Annual Cost:
$72/kW (30 x 1.2)
27
2. Marginal Capacity Costs Using the System Planning
Method: Planner Moves CCGT Unit Forward (2010$)
Minimum Capacity Required:
Requirement Met By:
60 MW
Accelerating a CCGT
unit by one year
Marginal Cost
CCGT Annualized Capacity Cost:
$230/kW
Fixed O&M:
$6/kW
CCGT Fuel Savings:
$63.3 million
♦ (Discounted Over Entire Life)
Other Savings:
$1.8 million (45 x 40,000)
♦ (Won’t Need to Purchase Firm Power)
Fuel and Other Savings per kW:
$186/kW (65.1
million/350,000)
Net Capacity Cost:
$50/kW (230 + 6 – 186)
Reserve Margin Adjustment:
$60/kW (20.00 x 1.2)
28
2. Marginal Generation Costs – Marginal Energy
Costs
For utilities in an RTO, use locational marginal prices (LMPs)
♦ In rate design, load serving entity’s (LSE) averaged LMPs across load
can be used
♦ For locationally-targeted demand-side management (DSM) programs,
more appropriate to use LMPs in/near targeted areas
♦ Need to go through bills from RTO to cull out energy-related costs:
ancillary services, etc.
For utilities not in RTO, use system lambda (λ):
Hourly System Lambda for a Typical Day
Hour Ending
1 a.m.
2
3
4
5
6
7
8
9
10
11
12 p.m.
System Lambda (mills/kWh)
16
16
16
16
36
36
54
54
54
54
54
36
29
Hour Ending
1 a.m.
2
3
4
5
6
7
8
9
10
11
12 a.m.
System Lambda ($/MWh)
36
36
36
36
54
54
54
54
54
54
36
36
Steps in Developing Marginal Cost-Based Rates
1. Carrying charges – annualizing investments
2. Marginal Generation Costs
a) Marginal generation capacity costs
b) Marginal generation energy costs
3. Marginal Transmission Capacity Costs
4. Marginal Distribution Costs
a) Marginal distribution customer-related costs
b) Marginal distribution capacity-(demand)-related costs
5. Determine appropriate costing periods
6. Attributing costs to costing periods
7. Adjustment of marginal costs for losses
8. Reconciling marginal cost-based rates with revenue
requirements
30
3. Marginal Transmission Capacity Costs
In an RTO, utility can use network service charge (or transmission service
charge). Needs to be adjusted for losses, which will be discussed later. Some
utilities in an RTO have some transmission and whose costs are not included in
the RTO tariff within their service territory. They will need to do calculations
similar to those for non-RTO utilities.
For many RTO utilities, the issue is which transmission investments are peak
demand-related. Some typical reasons for transmission investments:
a) To transfer power from generation to the distribution system (capacity
must be great enough to serve peak, even in the event of outages
b) To maintain or increase the reliability of the power system
c) Old equipment replacement
d) Tying remote generation to the central transmission system
e) Interconnecting with other utilities
Which are peak demand-related – Certainly a & b. What about the rest?
31
3. Marginal Transmission Capacity Costs (cont’d)
Three common methods:
♦ Actual Loads Method
• Use historical data and unitize peak demand-related investments
based on observed growth in demand
■ Some problems
♦
♦
Fails to account for construction lead times
Actual loads may differ from expected loads which were the
basis for investments
♦ Lead Time Method
• Use load growth over period beginning, for example, three years
after first investments considered in analysis and ending three
years after the last investment
■ Solves contemporaneity problem of actual loads method, but
still uses actual rather than expected demand
32
3. Marginal Transmission Capacity Costs (cont’d)
♦ System Planning Method
• Uses expected loads as the basis for unitizing costs
Regardless of method chosen need to additionally:
♦ Annualize unit costs
♦ Add O&M expenses
33
3. Marginal Transmission Capacity Costs (cont’d)
Three Methods for Determining
Transmission Peak Load Additions
Peak-Related Transmission Investments (2012$): $28,283,000
Growth in System Peak Load (MW)
Actual Loads Method
2007
2008
2009
2010
2011
2012
2013
2014
70
45
25
-35
65
----
Total Load Growth:
2007 – 2011:
170
Lead-Time Method
System Planning Method
----35
65
40
80
120
---50
55
40
80
120
2010 – 2014:
270
2010 – 2014:
345
34
3. Marginal Transmission Capacity Costs (cont’d)
The Unitization of Peak-Related Transmission Investments:
2007 – 2011 (2012 Dollars)
Actual Loads Method
Lead-Time Method
System Planning Method
Additional Peak-Related
Investment
$28,283,000
$28,283,000
$28,283,000
Growth in System
Peak (kW)
170,000
270,000
345,000
Unitized Cost (2010$/kW):
= (1) / (2)
$166.37/kW
$104.75/kW
$81.98/kW
35
3. Marginal Transmission Capacity Costs (cont’d)
The Calculation of Transmission O&M Costs
Cost
Transmission O&M
(Nominal $000)
Price Index
2010 = Base
Transmission O&M
(2010 $000)
System Peak
(MW)
2009
$1,304
0.7917
$1,647
1,938
$0.85
2010
1,550
0.8761
1,769
1,903
0.93
2011
1,427
0.9542
1,495
4,911
1,968
5,809
0.76
0.85
36
Average O&M
(2010 $/kW)
3. Marginal Transmission Capacity Costs (cont’d)
Steps in calculating marginal transmission capacity costs
1. Determine analysis period (can include historical and
forecast, possibly several different periods)
2. Convert investments into constant dollars
3. Categorize transmission investments as peak and nonpeak related
4. Using either of these three methods above, use load
additions as basis for investments
5. Unitize investment costs
6. Annualize the unitized costs
7. Add operations and maintenance costs
37
3. Marginal Transmission Capacity Costs (cont’d)
Summary of the Calculation of Marginal Transmission Capacity
Costs (2010 Dollars)
Total peak-related transmission
Investment (2007 – 2011):
$28,283,000
Total planned load growth
(system planning estimate):
345,000 kW
Utilized Cost
$81.98/kW
Annualized cost per kW:
$8.20/Kw (81.98 x .10)
Transmission O&M cost:
$0.85/kW
Marginal transmission capacity cost:
$9.05/kW
38
Steps in Developing Marginal Cost-Based Rates
1. Carrying charges – annualizing investments
2. Marginal Generation Costs
a) Marginal generation capacity costs
b) Marginal generation energy costs
3. Marginal Transmission Capacity Costs
4. Marginal Distribution Costs
a) Marginal distribution customer-related costs
b) Marginal distribution capacity-(demand)-related costs
5. Determine appropriate costing periods
6. Attributing costs to costing periods
7. Adjustment of marginal costs for losses
8. Reconciling marginal cost-based rates with revenue
requirements
39
4. Marginal Distribution Costs
Marginal distribution costs consists of two components
♦ Marginal distribution capacity (or demand) costs
♦ Marginal customer costs
• The distribution between these costs is not always clear
Marginal distribution customer-related costs methods are
♦ Minimum system approach
♦ Zero-intercept approach
♦ Engineering approach
40
4. Marginal Distribution Costs – Customer Related
Costs
The steps in the minimum system method are:
1. Determine the minimum-sized equipment currently installed –
minimum pole height, conductor size, transformer size,
service length, etc.
2. Multiply the minimum-sized equipment by the total capacity
(i.e., actual numbers of poles installed, circuit miles laid,
number of transformers, numbers of services, etc.)
3. Multiply by the current as expected (for future years) installed
cost
4. Unitize the customer-related marginal costs, using the number
of customers served by that portion or voltage level of the
distribution system
5. Annualize the investment costs
6. Add customer-related O&M and customer account costs
41
4. Marginal Distribution Costs – Customer Related
Costs (cont’d)
The steps in the zero-intercept method are:
1. Determine the analysis period
2. Convert all distribution cost data, net of meters and services, to
constant dollars
3. Separate distribution by voltage levels, i.e., primary and
secondary
4. For each voltage level analyzed, relate total distribution costs to
peak load using a trend or linear regression analysis
5. Extrapolate the trends to zero load and determine costs at zero
load
6. Unitize the costs using the number of customers by voltage level,
i.e., primary and secondary
7. Add the costs of meters and services
8. Annualize the investment costs
9. Add customer-related O&M and customer account costs
Optimally, the analysis will be forward-looking, but inevitably some
historical data will be used. N.B., this method sometimes produces
negative customer costs.
42
4. Marginal Distribution Costs – Customer Related
Costs (cont’d)
Constant Dollar Distribution Plant Versus Peak Load
(2010 Dollars)
Distribution
Plant
($000)
Distribution
Plant
($000)
Secondary
Voltage
Primary
Voltage
06
05 04
05
06
03
04
02
02
17,500
03
15,500
0
Peak Load
0
43
Peak Load
4. Marginal Distribution Costs – Customer Related
Costs (cont’d)
Zero Intercept Method Summary
Zero load plant investment:*
Secondary Voltage
$15,500,000
Primary Voltage
$17,500,000
Number of customers:
100,000
175,000
Unitized cost:
$155
$100
Plant cost by voltage level:
$255
($155 + $100)
$1,090
Meters and services:
$225
$1,010
Total Cost:
_______________________
$480
$2,200
*Excluding meters and services.
44
4. Marginal Distribution Costs – Customer Related
Costs (cont’d)
The steps in the engineering approach are:
1. Obtain average line length extension and average
transformer costs from data on customer installations,
all on a unitized basis
2. If need be, disaggregate costs to reflect differing
geographic conditions, building code requirements,
infrastructure growth in undeveloped areas
3. Annualize the investment costs
4. Add customer-related O&M and customer account costs
45
4. Marginal Customer Costs – Marginal Distribution
Capacity-Related Costs
Steps for estimating marginal distribution capacity costs
1. Determine time span to be analyzed
2. Classify distribution plant as either demand or customer-related
3. Separate demand-related plant by voltage levels, i.e., primary and
secondary levels
4. Convert all investments to constant dollars
5. Determine planned load growth by voltage level; i.e., primary and
secondary levels
6. Unitize the investment costs
7. Annualize the unitized costs
8. Add O&M Costs
Summary of Annualized Distribution Capacity Costs (2010$)
Primary voltage level:
$5.99 per kW per year
Secondary voltage level:
$16.51 per kW per year
46
Steps in Developing Marginal Cost-Based Rates
1. Carrying charges – annualizing investments
2. Marginal Generation Costs
a) Marginal generation capacity costs
b) Marginal generation energy costs
3. Marginal Transmission Capacity Costs
4. Marginal Distribution Costs
a) Marginal distribution customer-related costs
b) Marginal distribution capacity-(demand)-related costs
5. Determine appropriate costing periods
6. Attributing costs to costing periods
7. Adjustment of marginal costs for losses
8. Reconciling marginal cost-based rates with revenue
requirements
47
5. Determine Appropriate Costing Periods
Costing periods attempt to capture variations in marginal capacity and
energy costs for a system over the course of a year. Costing periods are
not the same as rating periods, but are developed as a step prior to
rating periods.
The goal is to group hours that are “similar” in their cost causation.
For utilities in RTOs, grouping by LMP is likely to be the easiest
approach, since the RTO’s cost variations will likely determine the
rating periods. However, the distribution utility may wish to group
hours based on a maximum stress to the distribution system.
For utilities not in RTOs, the usual approaches use metrics such as:
♦ LOLP
♦ System Loads
♦ System Lambda (similar to using LMPs)
The approaches include simple groupings to sophisticated statistical
analyses such as cluster analysis.
48
Steps in Developing Marginal Cost-Based Rates
1. Carrying charges – annualizing investments
2. Marginal Generation Costs
a) Marginal generation capacity costs
b) Marginal generation energy costs
3. Marginal Transmission Capacity Costs
4. Marginal Distribution Costs
a) Marginal distribution customer-related costs
b) Marginal distribution capacity-(demand)-related costs
5. Determine appropriate costing periods
6. Attributing costs to costing periods
7. Adjustment of marginal costs for losses
8. Reconciling marginal cost-based rates with revenue
requirements
49
6. Attributing Costs to Costing Periods – Marginal
Capacity Costs
Marginal capacity- (or demand-) related costs are annual and so must be
attributed to the costing periods developed above.
For utilities in RTOs, LMPs may be a proxy for a reliability measure such
as LOLP, but they may not. It is probably useful to check with the RTO
to determine if they can provide some form of hourly reliability index.
For utilities not in RTOs, three common measures are:
♦ LOLP
♦ Reserve margins
♦ Probability of negative margin
We illustrate below the use of absolute LOLP and relative LOLP on the
capacity allocation factors and the final cost attributions
50
6. Attributing Costs to Costing Periods – Marginal
Capacity Costs (cont’d)
Capacity Allocation Factors Derived From LOLP
Costing
Period
Summer:
Peak
Off-Peak
Winter:
Peak
Off-Peak
Absolute LOLP
(Days in 10 yrs.)
Relative LOLP
0.63
0.05
0.700
0.056
% of Capacity Costs
Assigned to Period
70.0%
5.6%
0.22
0.244
24.4%
+ 0.00
+ 0.00
+ 0.0%
0.90
1.000
100.0%
51
6. Attributing Costs to Costing Periods – Marginal
Capacity Costs (cont’d)
Attribution and Summary of Annualized
Marginal Capacity Costs by Costing Period
(2010 Dollars)
Total Cost
Relative LOLP
COST BY PERIOD
Summer
Winter
Peak
Off-Peak
Peak
Off-Peak
--
0.70
0.056
0.244
0.00
Marginal generating
capacity costs ($/kW)
$24.00
$16.80
$1.34
$5.86
0
Marginal transmission
capacity costs ($/kW)
$9.05
$6.34
$0.51
$2.20
0
Marginal distribution
capacity costs:
Primary ($/kW)
Secondary ($/kW)
$5.99
$16.51
$4.19
$11.56
$0.34
$0.92
$1.46
$4.03
0
0
52
6. Attribution of Costs to Costing Period – Marginal
Energy Costs
Calculating marginal energy costs by period consists of
aggregating the hourly costs to broader costing periods.
Three primary methods are used:
♦ Averaging all of the marginal energy costs in each period
♦ Selecting specific hourly costs that are arguably most
representative of each period, for example, the mode of
the highest marginal energy costs
♦ Weight-averaging, say by load, the marginal energy costs
Simple averaging is most common.
53
6. Attribution of Costs to Costing Period – Marginal
Energy Costs (cont’d)
Summary of System Lambda By Period
(2010¢/kWh)
Costing
Period
Summer:
Peak
Off-Peak
Winter:
Peak
Off-Peak
2006
2007
2008
2009
2010
Average
2006 - 2010
6.5
4.2
7.0
4.3
7.5
4.6
9.0
5.2
10.0
5.8
8.0
4.8
4.3
4.0
5.0
4.2
5.8
4.3
6.0
4.6
6.2
4.9
5.5
4.4
54
Steps in Developing Marginal Cost-Based Rates
1. Carrying charges – annualizing investments
2. Marginal Generation Costs
a) Marginal generation capacity costs
b) Marginal generation energy costs
3. Marginal Transmission Capacity Costs
4. Marginal Distribution Costs
a) Marginal distribution customer-related costs
b) Marginal distribution capacity-(demand)-related costs
5. Determine appropriate costing periods
6. Attributing costs to costing periods
7. Adjustment of marginal costs for losses
8. Reconciling marginal cost-based rates with revenue
requirements
55
7. Adjustment of Marginal Costs for Losses
♦ Losses occur when electrical energy is converted into heat energy. Think of
♦
♦
♦
♦
an electric stove.
Losses, as a percentage of throughput from one end of a line to the other, are
greatest at low voltages. (For example, the economies from using high
voltage direct current (HVDC) lines are largely due to their lower losses.)
Thus, the losses at the service drop to the residential customer are greater
than the losses for the service drop to the industrial customer because of the
higher voltage the latter is connected at.
Also, conversion from one voltage to another will incur losses. Thus,
residential customers will have the highest loss factors because they receive
power at the lowest voltage.
The losses must be made up by additional generation.
There are two varieties of losses that must be accounted for:
• Demand losses, which modify marginal capacity costs — generation,
transmission, and distribution
• Energy losses, which modify marginal energy costs
Are marginal customer costs modified for losses?
56
7. Adjustment of Marginal Costs for Losses –
Marginal Capacity Costs
♦ The next table provides the demand loss multiplier for each voltage
level. We assume transmission is at 115 kV, primary distribution at
13kV, and secondary at 4kV and lower.
♦ Thus, for a MW to be delivered at 4kV or lower, 1.09 MW needs to be
generated. These factors are multiplicative. N.B. Some demand loss
factors are defined not multiplicatively, but additively. You need to
know which you are given.
♦ Just as marginal generation capacity costs must be modified, so too
must marginal transmission and distribution costs.
• Although the demand loss multiplier for generation to the secondary
•
voltage level is 1.09, if that were used for the loss-adjusted marginal
transmission costs, it would overstate them. That is because 2.5% of the
power is lost moving from generation to secondary voltage must be
reduced (by dividing by 1.025) to 1.063 to reflect that these are only the
losses in going from transmission to secondary voltage.
A similar reasoning holds in adjusting for losses in going from transmission
to distribution, for adjusting for losses at the distribution level in going
from primary to secondary.
57
7. Adjustment of Marginal Costs for Losses –
Marginal Capacity Costs (cont’d)
Summary of Demand Loss Multipliers
Applicable to System Peak
Voltage Level
Transmission (115 kV)
Demand Loss Multiplier
1.025
Primary (13 kV)
1.050
Secondary (4 kV and lower)
1.090
58
7. Adjustment of Marginal Costs for Losses –
Marginal Capacity Costs (cont’d)
Marginal Generation Capacity Costs
Adjusted for Losses
Marginal Generation Cost After Loss Adjustment
_________________________________________
Costing
Period
Marginal Cost @
Transmission
Generation Level
Voltage
Primary
Voltage
Secondary
Voltage
Summer:
Peak
Off-Peak
$16.80
1.38
$17.22
1.37
$17.64
1.41
$18.31
1.46
Winter:
Peak
Off-Peak
$5.86
0
$6.01
0
$6.15
0
$6.39
0
Demand-loss
Multiplier:
1.000
1.025
1.050
1.090
59
7. Adjustment of Marginal Costs for Losses –
Marginal Capacity Costs (cont’d)
Marginal Transmission Capacity Costs
Adjusted for Losses
Loss-Adjusted Marginal Transmission Costs
_________________________________________
Costing
Period
Marginal Transmission
Costs @ the
Transmission Voltage
Primary
Voltage
Secondary
Voltage
Summer:
Peak
Off-Peak
$6.34
$0.51
$6.49
$0.52
$6.74
$0.54
Winter:
Peak
Off-Peak
$2.20
0
$2.25
0
$2.34
0
Demand-loss
Multiplier:
1.000
1.024a
1.063b
a
b
The loss multiplier equals 1.05 divided by 1.025 = 1.024.
The loss multiplier equals 1.09 divided by 1.025 = 1.063.
60
7. Adjustment of Marginal Costs for Losses –
Marginal Capacity Costs (cont’d)
Marginal Primary Distribution Cost
Adjusted for Losses
Costing
Period
Loss Adjusted
Marginal Primary
Distribution Cost
(Secondary Voltage)
Marginal Primary
Distribution Cost
(Primary Voltage)
Summer:
Peak
Off-Peak
$4.19
$0.34
$4.35
$0.35
Winter:
Peak
Off-Peak
$2.20
0
$1.52
0
Demand-loss
Multiplier:
a
1.000
The loss multiplier equals 1.09 divided by 1.05, or 1.038.
1.038a
61
7. Adjustment of Marginal Costs for Losses –
Marginal Capacity Costs (cont’d)
SUMMARY OF LOSS-ADJUSTED MARGINAL CAPACITY COSTS
(2010 Dollars per kW)
Transmission Voltage Customer
Costing
Period
Generation Transmission Total Margin
Marginal Cost Marginal Cost Capacity Cost
Summer:
Peak
Off-peak
$17.22
$1.37
$6.34
$0.51
$23.56
$1.88
Winter:
Peak
Off-peak
$6.01
$0.00
$2.20
$0.00
$8.21
$0.00
Primary Distribution Voltage Customer
Costing
Period
Primary
Total
Generation Transmission Distribution
Marginal
Marginal Cost Marginal Cost Marginal Cost Capacity Cost
Summer:
Peak
Off-peak
$17.64
$1.41
$6.49
$0.52
$4.19
$0.34
$28.32
$2.27
Winter:
Peak
Off-peak
$6.15
$0.00
$2.25
$0.00
$1.46
$0.00
$9.86
$0.00
Secondary Distribution Voltage Customer
Costing
Period
Generation Transmission
Marginal Cost Marginal Cost
Distribution
Marginal Cost
Primary
Secondary
Total
Capacity Cost
Summer:
Peak
Off-peak
$18.31
$1.46
$6.74
$0.52
$4.35
$0.35
$11.56
$0.92
$40.96
$3.25
Winter:
Peak
Off-peak
$6.39
$0.00
$2.34
$0.00
$1.52
$0.00
$4.03
$0.00
$14.28
$0.00
62
7. Adjustment of Marginal Costs for Losses –
Marginal Energy Costs
As was done for marginal capacity costs, marginal energy costs must
also be adjusted for losses.
Again, our approach is to use loss multipliers, in this case energy loss
multipliers, to perform the calculations.
Energy Loss Multipliers
Costing
Period
Transmission Voltage
Primary
Voltage
Secondary
Voltage
Summer:
Peak
Off-Peak
1.020
1.011
1.048
1.019
1.087
1.027
Winter:
Peak
Off-Peak
1.018
1.004
1.044
1.007
1.063
1.015
63
7. Adjustment of Marginal Costs for Losses –
Marginal Energy Costs (cont’d)
Loss-Adjusted Marginal Energy Costs
(2010 cents per kWh)
Delivery Voltage
Costing
Period
Summer:
Peak
Off-Peak
Winter:
Peak
Off-Peak
Transmission
Voltage
Primary
Voltage
Secondary
Voltage
8.16
4.85
8.38
4.89
8.70
4.93
5.60
4.42
5.74
4.43
5.85
4.47
64
Marginal Cost-Based Rates – Marginal Cost
Calculation Complexities and Issues
This has been a very brief overview. Here are some
additional calculations not included, but which would be in
a formal marginal cost-of-service analysis.
♦ Loadings for administrative and general (A&G), both plant
and non-plant related
♦ Non-working capital – materials and supplies,
prepayments, etc.
• No associated revenue requirement
♦ If projects are staged over several years there may be
contributions in aid of construction (CIAC) or Construction
Work in Progress (WIP) calculations
♦ Distribution utility could substitute relative probability of
peak in distribution system for the discussion of LOLP
♦ No inclusion of reserve margin in marginal distribution
capacity costs
65
Steps in Developing Marginal Cost-Based Rates
1. Carrying charges – annualizing investments
2. Marginal Generation Costs
a) Marginal generation capacity costs
b) Marginal generation energy costs
3. Marginal Transmission Capacity Costs
4. Marginal Distribution Costs
a) Marginal distribution customer-related costs
b) Marginal distribution capacity-(demand)-related costs
5. Determine appropriate costing periods
6. Attributing costs to costing periods
7. Adjustment of marginal costs for losses
8. Reconciling marginal cost-based rates with revenue
requirements
66
8. Reconciling Marginal Costs Based Rates With
Revenue Requirements
Generally, the revenue that would be collected under
marginal cost-based rates, whether standard blocked rates
or dynamic rates such as time-of-use (TOU), will not
precisely coincide with the revenue requirements permitted
under an embedded cost of service study.
Thus, the utility will need to adjust the marginal cost-based
rates. The two adjustments are:
♦ Revenue reconciliation
♦ Revenue repression
Revenue repression is more commonly applied to dynamic
rates, such as TOU.
67
8. Reconciling Marginal Costs Based Rates With
Revenue Requirements (cont’d)
Preliminary Marginal Cost Rates
Customer Class
Residential:
Peak
Off-Peak
Preliminary Rates
Demand:
Energy:
Demand:
Energy:
Customer
Commercial:
Peak
Off-Peak
Demand:
Energy:
Demand:
Energy:
Customer
Industrial:
Peak
Off-Peak
Demand:
Energy:
Demand:
Energy:
Customer
$5.00/kW/mo.
$57.00/MWh
$2.00/MWh
$32.50/MWh
$14.18/mo.
$4.60/kW/mo.
$7.00/MWh
$1.82/MWh
$32.50/MWh
$60.00/mo.
$4.20/kW/mo.
$55.00/MWh
$1.70/MWh
$31.90/MWh
$1050.00/mo.
Marginal Cost
Revenues
($ mil.)
Billing Unitsa
16,228 MW
1,234,153 MWh
17,395 MW
1,636,027 MWh
4,094,652 Bills
11,400 MW
1,171,841 MWh
14,400 MW
1,859,199 MWh
522,132 Bill
7,569 MW
1,077,533 MWh
12,832 MW
1,985,553 MWh
29,436 Bills
TOTAL
a
68
Revenue
Gap
($ mil.)
% Change from
Accounting
to Marginal
$81.140
70.347
34.790
53.171
58.062
$297.510
$287.000
$10.510
+3.7
$52.440
66.794
26.572
60.424
31.328
$237.558
$219.700
$17.858
+8.1
$31.790
59.264
21.814
63.339
30.098
$207.115
$191.500
$15.615
+8.2
$742.183
Total energy for the system is 8.965 * 103MWh
Accounting Cost
Rev. Require.
($ mil.)
$698.20
$43.98
+6.3
8. Reconciling Marginal Cost-Based Rates with
Revenue Requirements – Revenue Reconciliation
The goal in revenue reconciliation is to do the least harm to the
efficiency of the marginal cost-based rates.
They are five broad categories of adjustments. Often they are
combined for best results.
♦ Lump sum transfer
• Essentially a customer rebate. All customers receive a “lump sum” of
many equal to their share of the difference between allowed revenues
and projected revenues. If the marginal cost revenue is less than the
allowed revenues, a “lump sum” surcharge is added to each bill.
♦ Inverse elasticity
• Marginal cost-based rates are adjusted more for those customers who
have the most inelastic demand or to the component of the rate for
which the demand is least elastic. Nearly impossible to distinguish
customers with regard to price elasticity for each component of a rate.
69
8. Reconciling Marginal Cost-Based Rates with Revenue
Requirements – Revenue Reconciliation (cont’d)
♦ Customer Charge Adjustment
• An application of the inverse elasticity rate. The difference
between the allowed revenues and the marginal cost-based rate
revenues is accomplished by adjusting the bill’s customer cost
component. Demand and energy remain priced at marginal cost.
Results in unequal (sometimes very) customer class impacts.
♦ Demand Charge Adjustment
• Another application of the inverse elasticity rate. Same problems
as with customer charge adjustment
♦ Equiproportional Adjustment
• Increases (or decreases) all rate components for all classes equally
by a factor sufficient to yield the revenue requirement. A slight
variation on this caps the increase or decrease at a percentage
above (or below) the percent for the utility as a whole. Prevents
extreme increases (or decreases).
70
8. Reconciling Marginal Cost-Based Rates with Revenue
Requirements – Revenue Reconciliation (cont’d)
Examples (Based on chart on next page)
♦ Lump Sum Transfer
• $43.98M surplus revenues. Using energy $43.98M/(8,965 x 104
kWh) ≈ $0.005/kWh or 5 mill/kWh. Since average residential
customer uses ≈ 900 kWh/mo during peak four months, rebate ≈
$4.43/mo.
71
8. Reconciling Marginal Cost-Based Rates with Revenue
Requirements – Revenue Reconciliation (cont’d)
♦ Inverse Elasticity
• Assume all customers price elasticity of demand during all rating
periods -0.5 and for energy it is -1.0.
• For industrial customers, for which $15.615 (8.2%) would be overcollected yields the following rate:
Peak
Off Peak
Demand
($/kW/
1.46
month)
3.63
Energy
29.73
($/MWh)
51.26
Customer: $1,000/month
72
8. Reconciling Marginal Cost-Based Rates with Revenue
Requirements – Revenue Reconciliation (cont’d)
♦ Customer Charge
• If revenue reconciliation is small, a customer charge adjustment
may be sufficient. For residential class the over-collection is ≈
$10.5M. Dividing this by the billing units yields a customer charge
reduction $2.57/month and, thus, an adjusted customer charge of
$11.61/month.
♦ Equiproportional Adjustment
• For the commercial class, marginal cost-based rate revenues
exceed the revenue requirement by ≈ $17.9M or ≈ 7.5%. This, all
elements of the rate would be reduced by 7.5%.
73
8. Reconciling Marginal Cost-Based Rates with Revenue
Requirements – Revenue Reconciliation (cont’d)
When a new rate structure or rate is introduced, customers respond by
changing their loads. Utilities can account for the anticipated load changes in
the billing determinants or through an adjustment account, much like a fuel
adjustment clause, that restores revenues back to target levels. For reasons
that are unknown to me, these are known as revenue repression mechanisms.
Such mechanisms typically take one of two forms:
♦ Ex ante
• In ex ante mechanisms, the utility attempts to account for the load
changes in the billing determinants.
♦ Ex post
• Ex post mechanisms attempt to adjust revenues after they have been
filed and take effect.
These two approaches can be combined. For example, a utility can implement
a dynamic pricing program which, perhaps based on pilot information, attempts
to account for customer response and which also has a periodic tune-up
mechanism, perhaps a balancing account, which makes the utility whole
between rate cases.
74
8. Reconciling Marginal Cost-Based Rates with Revenue
Requirements – Ex Ante Revenue Repression
Residential consumption (annual kWh)
Peak period
Off-peak period
TOTAL
542,802,800
361,369,200
904,172,000
Assumed consumption shift (5%)
Adjusted peak
Adjusted off-peak
TOTAL
515,662,660
388,509,340
904,172,000
Allocated residential expenses (preadjustment)
Period
Peak
Off-peak
TOTAL
Costs
$24,968,929.00
$7,950,122.00
$32,919,051.00
Allocated residential expenses (post-adjustment)
Peak
$24,751,808.00
Off-peak
$7,770,187.00
TOTAL
$32,521,994.00
Unit Costs
($/kWh)
0.046
0.022
0.036
0.046
0.022
0.036
In this example, the initial assumed flat rate is $0.036/kWh. The time differentiated rate
is $0.046/kWh on-peak and $0.022/kWh off-peak. The example also assumes that there
will be a shift in consumption from on-peak to the off-peak period of 5%. This is based on
assumed on-peak price elasticity of:
-0.18 = -0.05/0.28
where 0.28 = (0.46 – 0.36)/0.36
i.e., the percentage change in rates going from the flat rate to the on-peak rate. Note
that the implied off-peak price elasticity is only -0.08.
75
8. Reconciling Marginal Cost-Based Rates with Revenue
Requirements – Ex Post Revenue Repression
Generally, these are the steps in an ex post revenue
repression mechanism:
♦ After the rate is in effect, utility compares revenues collected with
anticipated revenues using billing determinants
♦ Utility calculates the difference between actual and expected and places this
in adjustment pool
♦ Periodically, say every quarter, utility adjusts rate components for the
increase/decrease in adjustment pool
Ex Post Revenue Repression Adjustment
Peak
1. Expected consumption (kWh)
2. Expected revenue ($)
3. Actual consumption (kWh)
4. Actual revenue ($)
5. Adjustment pool (2)-(4) ($)
6. Pool per kWh (5)/(3) ($/kWh)
7. Base rate (per kWh)
8. Adjustment clause (6)
Off-Peak
Total
542803800
361869200
904673000
$24,968,975.00 $7,950,122.00 $32,919,097.00
515663610
389009390
904673000
$23,720,526.00 $8,558,206.00 $32,278,732.00
$1,248,449.00 -$608,084.00
$640,365.00
$0.004
-$0.002
$0.046
-$0.022
$0.002
-$0.002
-
76