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Copyright © 2012 The Brattle Group, Inc. www.brattle.com

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

2

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.

3

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?

4

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.

5

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

6

Traditional Markets

Customer Customer

Generator Generator

Wholesaler/Transmitter Wholesaler/Transmitter

Distributor Distributor

Utility A Utility B

Decentralized Bilateral Trade

7

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

8

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

9

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

10


Wholesale competition - Centralized Market Design

Genco Genco Genco Genco Genco

LSE

ISO Wholesale Market Regional Transmission Organization

LSE LSE Large customer

Consumers Consumers Consumers

11


Centralized Wholesale Market/Decentralized Retail Market

Genco Genco Genco Genco Genco

ISO Wholesale Market Regional Transmission Organization

Retail market LSEs

Consumer Consumer Consumer Consumer

Retailer Retailer Retailer Large

customer

12

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

13

The Logic of Dispatch Units

Demand

Supply

MW

$ /

MW

Excess Capacity

Demand

Supply

MW

$ /

MW

Demand Spike

14

Locational Marginal Prices Across a Day

Locational Marginal Prices on August 1, 2002NY City-PJM-Cinergy

0

20

40

60

80

100

120

140

160

180

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25Hour

Pric

es ($

/MW

h)

NY CityCinergyCentral NY

Source: New York ISO and Intercontinental Exchange

15

Cost Element Traditional Centralized Restructured

Decentralized Restructured

Production (Generation)

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.)

Transmission

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.



16

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

17







requirements

18

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)

19

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

20

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

21

1. Comparison of Carrying Charges in Nominal Dollars

Revenue Requirement

$

Years 0 10 20 30

Economic Carrying Charge

Levelized Carrying Charge

22

1. Comparison of Carrying Charges in Constant Dollars

$

Years 0 10 20 30

Revenue Requirement

Economic Carrying Charge

Levelized Carrying Charge

23







requirements

24

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?

1,000

500

7,000 8,760Hours

Load (MW)

1 KW

0.5 KW

MC = cost/kW (1000/500) RM

25

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

26

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.

27

Marginal Capacity Costs Using the System Planning Method: Planner Builds Combustion Turbine

Minimum Capacity Required: 60 MW Requirement Met By: 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)

28

2. Marginal Capacity Costs Using the System Planning Method: Planner Moves CCGT Unit Forward (2010$)

Minimum Capacity Required: 60 MW Requirement Met By: 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)

29

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 System Lambda (mills/kWh) Hour Ending System Lambda ($/MWh) 1 a.m. 16 1 a.m. 36 2 16 2 36 3 16 3 36 4 16 4 36 5 36 5 54 6 36 6 54 7 54 7 54 8 54 8 54 9 54 9 54 10 54 10 54 11 54 11 36 12 p.m. 36 12 a.m. 36

30







requirements

31

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?

32

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

33


♦ 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

34


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 Lead-Time Method System Planning Method 2007 70 -- -- 2008 45 -- -- 2009 25 -- -- 2010 -35 -35 50 2011 65 65 55 2012 -- 40 40 2013 -- 80 80 2014 -- 120 120 Total Load Growth: 2007 – 2011: 2010 – 2014: 2010 – 2014: 170 270 345

35


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

36


The Calculation of Transmission O&M Costs

Transmission O&M Price Index Transmission O&M System Peak Average O&M Cost (Nominal $000) 2010 = Base (2010 $000) (MW) (2010 $/kW) 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 1,968 0.76 4,911 5,809 0.85

37


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 non-

peak 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

38


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

39







requirements

40

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

41

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

42

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.

43


Constant Dollar Distribution Plant Versus Peak Load (2010 Dollars)

Distribution Plant ($000)

Distribution Plant ($000)

Primary Voltage

Secondary Voltage

Peak Load Peak Load

02 03

05 04 06

17,500

05 04 06

02 03

15,500

0 0

44


Zero Intercept Method Summary

Secondary Voltage Primary Voltage Zero load plant investment:* $15,500,000 $17,500,000 Number of customers: 100,000 175,000 Unitized cost: $155 $100 Plant cost by voltage level: $255 $1,090 ($155 + $100) Meters and services: $225 $1,010 Total Cost: $480 $2,200 _______________________ *Excluding meters and services.

45


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

46

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

47







requirements

48

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.

49







requirements

50

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

51

6. Attributing Costs to Costing Periods – Marginal Capacity Costs (cont’d)

Capacity Allocation Factors Derived From LOLP

Costing Absolute LOLP % of Capacity Costs Period (Days in 10 yrs.) Relative LOLP Assigned to Period Summer: Peak 0.63 0.700 70.0% Off-Peak 0.05 0.056 5.6% Winter: Peak 0.22 0.244 24.4%

Off-Peak + 0.00 + 0.00 + 0.0%

0.90 1.000 100.0%

52

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 Peak Off-Peak Peak Off-Peak

Relative LOLP -- 0.70 0.056 0.244 0.00

Marginal generatingcapacity costs ($/kW) $24.00 $16.80 $1.34 $5.86 0

Marginal transmissioncapacity costs ($/kW) $9.05 $6.34 $0.51 $2.20 0

Marginal distributioncapacity costs:Primary ($/kW) $5.99 $4.19 $0.34 $1.46 0Secondary ($/kW) $16.51 $11.56 $0.92 $4.03 0

Summer WinterCOST BY PERIOD

53

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.

54

6. Attribution of Costs to Costing Period – Marginal Energy Costs (cont’d)

Summary of System Lambda By Period (2010¢/kWh)

Costing Average Period 2006 2007 2008 2009 2010 2006 - 2010 Summer: Peak 6.5 7.0 7.5 9.0 10.0 8.0 Off-Peak 4.2 4.3 4.6 5.2 5.8 4.8 Winter: Peak 4.3 5.0 5.8 6.0 6.2 5.5 Off-Peak 4.0 4.2 4.3 4.6 4.9 4.4

55







requirements

56

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?

57

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.

58

7. Adjustment of Marginal Costs for Losses – Marginal Capacity Costs (cont’d)

Summary of Demand Loss Multipliers Applicable to System Peak

Voltage Level Demand Loss Multiplier Transmission (115 kV) 1.025 Primary (13 kV) 1.050 Secondary (4 kV and lower) 1.090

59


Marginal Generation Capacity Costs Adjusted for Losses

Marginal Generation Cost After Loss Adjustment _________________________________________ Marginal Cost @ Costing Transmission Primary Secondary Period Generation Level Voltage Voltage Voltage Summer: Peak $16.80 $17.22 $17.64 $18.31 Off-Peak 1.38 1.37 1.41 1.46 Winter: Peak $5.86 $6.01 $6.15 $6.39 Off-Peak 0 0 0 0 Demand-loss Multiplier: 1.000 1.025 1.050 1.090

60


Marginal Transmission Capacity Costs Adjusted for Losses

Loss-Adjusted Marginal Transmission Costs

_________________________________________ Marginal Transmission Costing Costs @ the Primary Secondary Period Transmission Voltage Voltage Voltage

Summer: Peak $6.34 $6.49 $6.74 Off-Peak $0.51 $0.52 $0.54 Winter: Peak $2.20 $2.25 $2.34 Off-Peak 0 0 0 Demand-loss Multiplier: 1.000 1.024a 1.063b

a The loss multiplier equals 1.05 divided by 1.025 = 1.024. b The loss multiplier equals 1.09 divided by 1.025 = 1.063.

61


Marginal Primary Distribution Cost Adjusted for Losses

Loss Adjusted

Marginal Primary Marginal Primary Costing Distribution Cost Distribution Cost Period (Primary Voltage) (Secondary Voltage)

Summer: Peak $4.19 $4.35 Off-Peak $0.34 $0.35 Winter: Peak $2.20 $1.52 Off-Peak 0 0 Demand-loss Multiplier: 1.000 1.038a

a The loss multiplier equals 1.09 divided by 1.05, or 1.038.

62


SUMMARY OF LOSS-ADJUSTED MARGINAL CAPACITY COSTS(2010 Dollars per kW)

Transmission Voltage Customer

Costing Generation Transmission Total MarginPeriod Marginal Cost Marginal Cost Capacity Cost

Summer:Peak $17.22 $6.34 $23.56

Off-peak $1.37 $0.51 $1.88

Winter:Peak $6.01 $2.20 $8.21

Off-peak $0.00 $0.00 $0.00

Primary Distribution Voltage Customer

Primary TotalCosting Generation Transmission Distribution MarginalPeriod Marginal Cost Marginal Cost Marginal Cost Capacity Cost

Summer:Peak $17.64 $6.49 $4.19 $28.32

Off-peak $1.41 $0.52 $0.34 $2.27

Winter:Peak $6.15 $2.25 $1.46 $9.86

Off-peak $0.00 $0.00 $0.00 $0.00

Secondary Distribution Voltage Customer

Generation Transmission TotalCosting Marginal Cost Marginal Cost Capacity CostPeriod Primary Secondary

Summer:Peak $18.31 $6.74 $4.35 $11.56 $40.96

Off-peak $1.46 $0.52 $0.35 $0.92 $3.25

Winter:Peak $6.39 $2.34 $1.52 $4.03 $14.28

Off-peak $0.00 $0.00 $0.00 $0.00 $0.00

DistributionMarginal Cost

63

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 Primary Secondary Period Transmission Voltage Voltage Voltage

Summer: Peak 1.020 1.048 1.087 Off-Peak 1.011 1.019 1.027

Winter: Peak 1.018 1.044 1.063 Off-Peak 1.004 1.007 1.015

64

7. Adjustment of Marginal Costs for Losses – Marginal Energy Costs (cont’d)

Loss-Adjusted Marginal Energy Costs (2010 cents per kWh)

Delivery Voltage Costing Transmission Primary Secondary Period Voltage Voltage Voltage Summer: Peak 8.16 8.38 8.70 Off-Peak 4.85 4.89 4.93 Winter: Peak 5.60 5.74 5.85 Off-Peak 4.42 4.43 4.47

65

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

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requirements

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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.

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8. Reconciling Marginal Costs Based Rates With Revenue Requirements (cont’d)

Preliminary Marginal Cost Rates Marginal Cost Accounting Cost Revenue % Change from

Revenues Rev. Require. Gap Accounting Billing Unitsa ($ mil.) ($ mil.) ($ mil.) to Marginal

Residential: Peak Demand: $5.00/kW/mo. 16,228 MW $81.140Energy: $57.00/MWh 1,234,153 MWh 70.347

Off-Peak Demand: $2.00/MWh 17,395 MW 34.790Energy: $32.50/MWh 1,636,027 MWh 53.171

Customer $14.18/mo. 4,094,652 Bills 58.062$297.510 $287.000 $10.510 +3.7

Commercial: Peak Demand: $4.60/kW/mo. 11,400 MW $52.440Energy: $7.00/MWh 1,171,841 MWh 66.794


Customer $60.00/mo. 522,132 Bill 31.328$237.558 $219.700 $17.858 +8.1

Industrial: Peak Demand: $4.20/kW/mo. 7,569 MW $31.790Energy: $55.00/MWh 1,077,533 MWh 59.264


Customer $1050.00/mo. 29,436 Bills 30.098$207.115 $191.500 $15.615 +8.2

TOTAL $742.183 $698.20 $43.98 +6.3

aTotal energy for the system is 8.965 * 103MWh

Customer Class Preliminary Rates

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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.

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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).

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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.

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♦ 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 over-

collected yields the following rate:

Peak Off Peak

Demand ($/kW/month) 3.63Energy ($/MWh) 51.26

1.46

29.73Customer: $1,000/month

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♦ 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%.

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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.

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8. Reconciling Marginal Cost-Based Rates with Revenue Requirements – Ex Ante Revenue Repression

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.

Residential consumption (annual kWh)Peak period 542,802,800Off-peak period 361,369,200TOTAL 904,172,000

Assumed consumption shift (5%)Adjusted peak 515,662,660Adjusted off-peak 388,509,340TOTAL 904,172,000

Allocated residential expenses (preadjustment)

Period CostsUnit Costs ($/kWh)

Peak $24,968,929.00 0.046Off-peak $7,950,122.00 0.022TOTAL $32,919,051.00 0.036

Allocated residential expenses (post-adjustment)Peak $24,751,808.00 0.046Off-peak $7,770,187.00 0.022TOTAL $32,521,994.00 0.036

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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 Off-Peak Total

1. Expected consumption (kWh) 542803800 361869200 9046730002. Expected revenue ($) $24,968,975.00 $7,950,122.00 $32,919,097.003. Actual consumption (kWh) 515663610 389009390 9046730004. Actual revenue ($) $23,720,526.00 $8,558,206.00 $32,278,732.005. Adjustment pool (2)-(4) ($) $1,248,449.00 -$608,084.00 $640,365.006. Pool per kWh (5)/(3) ($/kWh) $0.004 -$0.002 -7. Base rate (per kWh) $0.046 -$0.022 -8. Adjustment clause (6) $0.002 -$0.002 -

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