Page 1

Documentation of the Retail Price Model

DRAFT

June 16, 2014

Developed by ICF International
Page 2

1. Introduction  

The Retail Price Model (RPM) provides a first‐order estimate of average retail electricity prices using

information from the EPA Base Case v5.13 Base Case or other scenarios analyzed for the period 2016 to

2050 for each of the 64 IPM model regions.  This model was developed by ICF at the direction of EPA in

support of the EPA Base Case v5.13.   

The remainder of this memo provides an overview of the model and documents the model calculations,

inputs and outputs.

1.1. Background

IPM is a wholesale power market model that projects wholesale prices paid to generators.  Electricity

consumers—industrial, commercial and residential customers—face a retail price for electricity that is

higher than the wholesale price because it includes the cost of wholesale power and the costs of

transmitting and distributing electricity to end‐use consumers. The RPM was developed to estimate

retail prices of electricity based on outputs of EPA’s Base Case using IPM and a range of other

assumptions, including the method of regulation and price‐setting in each state.

Traditionally, cost‐of‐service (COS) or Rate‐of‐Return regulation sets rates based on the estimated

average costs of providing electricity to customers plus a “fair and equitable return” to the utility’s

investors.   States that impose cost‐of‐service regulation typically have one or more investor owned

utilities (IOUs) which own and operate their own generation, transmission and distribution assets.  They

are also the retail service provider for their franchised service territory.  IOUs can also buy power from

neighboring IOUs or organized markets but do so only to secure incremental power that is less

expensive than power generated by its own assets.  Under this regulatory structure, retail power prices

are based on average historical costs and are established for each class of service by state regulators

during periodic rate case proceedings.   

During the 1990s, certain states began to deregulate their retail electricity market. In most deregulated

states, vertically integrated utilities sold off their generating assets and became distributors of power.

Under the retail choice programs implemented as part of deregulation, individual retail customers were

allowed to choose their electricity supplier while still receiving delivery over the power lines of the

electric utility. These deregulated electricity markets are designed to reflect the marginal costs of

generating and delivering power in a competitive marketplace.  Retail service providers secure

necessary power supplies through a combination of long‐term contracts and purchased power in the

wholesale spot market.  Wholesale power pricing is based on the marginal costs of generating power

and the costs of transporting that power to load centers.

The restructuring1 of the electric power industry in the U.S. historically fell under the jurisdiction of both

federal and state authorities.  Due to states’ differing choices in regulatory process, the extent and

nature of power market deregulation varies widely across the U.S.  As a result, differences in regional

power market structures impact how electric retail prices are set in those markets.  Regional power

                                                            

1 The restructing process started in 1978 with passage of Public Utilities Regulatory Policy Act (PURPA), which 

required utilities to purchase power from qualifying facilities at the utilities avoided cost. Following PURPA, Energy 

Policy Act of 1992 among other provisions, allowed for creation of independent power producers. In 1996, FERC 

Order 888 addressed inadequacies of transmission access and pricing. 
Page 3

markets can be generally grouped into three broad categories: deregulated/competitive, regulated/COS,

and a combination of those two structures.   

The RPM accounts for this diversity of regulated and deregulated market structures in U.S. by calculating

both competitive and cost‐of‐service retail prices for each region and later allocating and weighting

those two prices to individual IPM regions according to the market structure(s) determined as the most

representative regulatory model for each region.    

1.2. The Retail Price Model  

The retail price of electricity to customers is comprised of generation, transmission and distribution

components.  

The RPM incorporates two price models to capture both deregulated markets with competitive pricing

and regulated markets with cost‐of‐service pricing.  In both models, transmission and distribution (T&D)

costs are assumed to remain regulated and the related price component is based on the average costs

to build, operate and maintain these systems. These models use generation‐related outputs from an

IPM‐modeled scenario together with T&D and other cost projections and assumptions from EIA’s AEO

2013 Reference Case2 to estimate the retail price of electricity. The two models are:  

• The Competitive Price Model, which estimates prices based on wholesale power prices,

transmission and distribution costs and applicable taxes.

• The Cost‐of‐Service (COS) Model, which estimates prices based on average cost to generate

power and includes regulated returns to utilities, taxes, and transmission and distribution costs.

While deregulation is implemented at the state level, individual IPM model regions can include multiple

states.  The share of each IPM region that is subject to deregulated/cost‐of‐service ratemaking is

obtained directly from EIA’s AEO 2013. All IPM regions that are individually mapped to a NEMS region

get the same deregulation share as the corresponding NEMS region.  In multi‐state IPM regions, the

regional retail price is a function of the average degree of deregulation across the included states.  

Attachment 1 presents the characterization of retail price regulation assumed for each IPM region. The

calculation is shown in Equation 1. For example, if the competitive market price of the ERC_REST region

is calculated to be $40/MWh while the COS price is calculated to be $80/MWh, and the deregulation

share is 88% while the COS share is 12%, the retail price in ERC_REST is calculated as $40/MWh × 88% +

$80/MWh × 12% = $44.8/MWh.

●●●

Equation 1 Regional Average Retail Price

Regional Average Price (mills/kWh) = Competitive Retail Power Price * Deregulation Share (%) + Cost‐

of‐Service Retail Power Price * Cost‐of‐Service Share (%)

●●●

                                                            

2 http://www.eia.gov/forecasts/archive/aeo13/index.cfm and by personal communication. 
Page 4

The rest of this document explains how retail prices are calculated under the competitive and cost‐of‐

service models, and how the RPM estimates an average retail price for IPM regions that include both

competitive and cost‐of‐service states.  

1.2.1. Competitive Retail Power Price Model

Figure 1 summarizes the structure of the model that calculates competitive retail power prices for those

deregulated regions noted in Attachment 1 and for those portions of the regions with mixed retail

market structures.  All of the inputs to the model either come from an IPM‐modeled scenario or the AEO

2013 Reference Case.  

Competitive retail power prices comprise three components:  competitive generation cost, transmission

charge, and distribution charge.  Equation 2 illustrates the formula for calculating the competitive retail

power price.  

●●●

Equation 2. Competitive Retail Power Price (Delivered)

Competitive Retail Power Price (Mills/kWh) = (Competitive Generation Cost per kWh + Transmission

Charge + Distribution Charge)  

●●●

Competitive generation costs (in mills/kWh) are calculated as a summation of the marginal cost of

electricity generation per kilowatt‐hour of sales, the cost of maintaining adequate generating capacity to

meet reserve margins over and above the peak load embedded in each kilowatt‐hour of sales, and the

cost of renewable energy credits (REC) associated with the compliance of Renewable Portfolio Standard

(RPS) per kilowatt‐hour of sales.3  See Equation 3.

Transmission charges (in mills/kwh) and distribution charges (in mills/kwh) for use in Equation 2 are

taken from EIA’s AEO 2013 Reference Case at a NEMS region level and mapped to the appropriate IPM

region. These charges reflect the cost of operating transmission and distribution infrastructure to move

power from generators to retail end‐use consumers in each region.  Unlike the generation costs, which

are based on IPM projections, transmission and distribution charges do not change across modeled IPM

scenarios.

●●●

Equation 3. Competitive Generation Cost

Competitive Generation Cost (mills/kWh) = (Marginal Energy Cost + Reliability Cost + REC Cost) * (1 +

Tax Rate)

●●●

The three costs illustrated in Equation 3 have the following key components:   

                                                            

3 A Renewable Portfolio Standard (RPS) is a regulatory requirement that utilities meet a specified percentage of their 

power supply using qualified renewable resources. 
Page 5

The marginal energy cost (in mills/kwh), is a direct output of IPM for each region. This represents an

energy‐weighted average annual price of power (total cost divided by total generation).  See Equation 4.

The reliability cost (in mills/kWh) is the product of the capacity price (in $/kW‐year), a direct output of

IPM for each region, and the region’s reserve requirement4 (kW), which is then distributed evenly across

total sales.  A capacity price is typically expressed as an annual payment for each kilowatt kept in

service.  Retail ratepayers do not face the capacity price directly; instead, the capacity price determines

the total annual reliability cost, which is then spread out over total sales such that a fraction of the total

reliability cost is recovered with each kilowatt‐hour sold.  This is the cost of ensuring that adequate

capacity is available to meet peak loads plus a reserve margin determined by electric reliability

authorities in each region.5  

The REC cost (in mills/kWh) is the product of the REC Price (mills/kWh, calculated endogenously at the

NEMS region level) and the proportion of renewables per kWh of sales required to comply with state

renewable portfolio standard (RPS) policy requirements.   The REC cost reflects the cost premium for

generating electricity from renewable resources relative to the market price of conventionally generated

electricity.

A tax rate representing state and local taxes is then applied to the sum of these three price components.

Tax rates at the NEMS region level were obtained from EIA’s AEO 2013.  

●●●

Equation 4. Marginal Energy Cost and Capacity Cost  

Marginal Energy Cost and Capacity Cost (mills/kWh) = [Marginal Energy Price (mills/kWh) + (Capacity Price 

($/kw-year) × (1 + Reserve Margin)) / (8.76 × Load Factor))] / (1 – Distribution Loss Factor %) 

●●●

The distribution loss factor accounts for power losses that occur as the power moves through the

transmission and the distribution grid. 6  The marginal energy cost and capacity cost equation

incorporates the distribution loss factor so that retail rates estimated by the model reflect rates of total

electricity generated, rather than just the electricity delivered.  The distribution loss factors in RPM are

calculated as the ratio of the NEMS region level electricity sales and net‐energy‐for‐load projections

from AEO 2013 Reference Case. The NEMS region level estimates are mapped to IPM model regions.

1.2.2. Cost‐of‐Service (Regulated) Retail Power Price Model

The second module of the RPM calculates a cost‐of‐service electricity price based on historical average

costs for those regions.   Figure 2 summarizes the methodology for developing prices on a cost‐of‐

                                                            

4 A region’s reserve requirement is a function of its peak load and reserve margin. 

5 See Documentation for EPA Base Case v.5.13 Using the Integrated Planning Model section 2.2.3, available at: 

http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev513.html 

6 The voltage levels in the transmission network are higher than those in the distribution network. Lower voltages in 

the distribution network result in higher losses relative to the transmission network. 
Page 6

service basis.  In addition to the cost of generation, as in the competitive price calculation, the cost‐of‐

service price to customers also includes the recovery of costs associated with T&D facilities and services.

Given the assumption that T&D charges are regulated, these charges are identical in the competitive

and the cost‐of‐service models. Equation 5 illustrates the formula for calculating the cost‐of‐service

retail power price.  

●●●

Equation 5. Cost‐of‐Service Electricity Price

Cost‐of‐Service Retail Power Price = (Final Cost of Power Generation + Transmission Charge +

Distribution Charge)

●●●

The final cost of power generation in Equation 5 is comprised of the following expenses:  

The regional Average Cost of Power Sales (mills/kWh) is the sum of total costs for generation divided by

total sales7 in each region.  The total generation costs include fuel costs, variable operation and

maintenance (VOM) costs, fixed operation and maintenance (FOM) costs, annualized capital costs, CO2

transportation and storage costs, wholesale power costs for interregional transactions, and REC

transaction costs in each region. These are all projected outputs of IPM.

Utility Depreciation Costs (in mills/kWh) represent the ability of regulated generators to recover the

costs of depreciated capital.  These costs are obtained directly from EIA’s AEO 2013. All IPM regions that

are individually mapped to a NEMS region get the same NEMS region level utility depreciation cost.

In COS regions, utilities are allowed by regulators to earn a return on their rate base.  The rate of return

is regulated regionally, and is reflected in this model as Return to Equity and Debt (in mills/kWh).  These

charges are obtained directly from EIA AEO 2013. All IPM regions that are individually mapped to a

NEMS region get the same Return to Equity and Debt as the corresponding NEMS region.

The capital costs of existing units constructed prior to 2012 are not explicitly modeled in IPM.  The utility

depreciation costs noted above capture capital cost recovery of such units built by regulated utilities.   

Since the capital costs of non‐utility generators (NUG) constructed prior to 2012 are not accounted for in

model results or in the utility depreciation costs, we add an estimated NUG Adder (in mills/kwh) to

account for the capital costs that are passed through to ratepayers in the retail rate.   This adder is based

on EIA’s AEO 2013.

Generation is subject to state and local taxes, and these taxes are generally passed through to

ratepayers in the COS retail rate.  Therefore, we add a regional Tax Rate (in mills/kWh) to the retail

power price in COS regions.  This rate is estimated regionally by summing the total regional tax dollars

and dividing by the sum of fuel, O&M, wholesale, NUG, depreciation, and return costs as summarized by

EIA’s AEO 2013.

Equation 6 summarizes the calculation for calculating the Final Cost of Power Generation.

                                                            

7 The total sales in each region are calculated as the product between net-energy-for-load and the distribution loss 

factor. 
Page 7

●●●

Equation 6. Final Cost of Power Generation

Final Cost of Power Generation (mills/kWh) = (Average Cost of Power Sales + Utility Depreciation Costs

+ Return to Equity and Debt + NUG Adder) × (1+Tax Rate)  

●●●

1.3. Caveats

The RPM discussed in this memo is a first‐order approach for estimating the retail price of electricity

based on IPM‐projected outputs as implemented in the modeling platform used to analyze EPA Base

Case v5.13. This model makes several assumptions to simplify the data gathering and price estimation

process. These assumptions include the use of EIA’s Annual Energy Outlook 2013 as the primary source

for non‐IPM related RPM inputs and then assuming that those inputs remain constant across IPM model

runs, even for modeling scenarios in which electricity demand is no longer assumed to be consistent

with AEO 2013’s reference case. For example, a modeling scenario assuming increased energy efficiency

would yield lower electricity consumption over which fixed costs for T&D could be recovered via the

T&D charge in mills/kWh.  If fixed costs for T&D are assumed to persist at the same level in the future

regardless of increased energy efficiency, the T&D charge could be expected to increase beyond the

assumed charge taken from the AEO2013 reference case.  

However, a review of projected T&D rates from the AEO 2013 reference case and two scenarios with

different levels of electricity demand reduction shows that the projected impact of change in demand

on the T&D component of retail rates is relatively small.  Tables 1 and 2 summarize the 2020 and 2030

projected transmissions and distribution rates from the AEO 2013 reference case, the high demand

technology case, and the best available demand technology case.  These cases represent a 6% to 16%

reduction in demand, relative to the reference case, over the 2020‐2030 time horizon.

Table 1.  Projected Prices by Service Category (2011 cents per kilowatt‐hour)

   2020 2030

     Generation    Transmission    Distribution    Generation    Transmission    Distribution

Reference 5.6 1.1 2.8 6.0 1.1 2.6

High technology 5.4 1.1 2.9 5.7 1.1 2.7

Best available technology 5.3 1.1 2.9 5.4 1.1 2.7

   
Page 8

Attachment 1.  Assumptions Regarding State of Retail Rate Regulation for IPM Regions

State of Retail

Regulation

IPM Region

Code

NEMS Region

Code

Deregulation Share

(%)

Cost‐of‐Service Share

(%)

Full Deregulation with

Competitive Pricing

NY_Z_J NYCW 100% 0%

NY_Z_K NYLI 100% 0%

NY_Z_A&B NYUP 100% 0%

NY_Z_C&E NYUP 100% 0%

NY_Z_D NYUP 100% 0%

NY_Z_F NYUP 100% 0%

NY_Z_G‐I NYUP 100% 0%

PJM_EMAC RFCE 100% 0%

PJM_PENE RFCE 100% 0%

PJM_SMAC RFCE 100% 0%

PJM_WMAC RFCE 100% 0%

Full Regulation with

Costs of Service Pricing

FRCC FRCC 0% 100%

WECC_CO RMPA 0% 100%

SPP_N SPNO 0% 100%

S_C_KY SRCE 0% 100%

S_C_TVA SRCE 0% 100%

S_SOU SRSE 0% 100%

PJM_Dom SRVC 0% 100%

S_VACA SRVC 0% 100%

Mix of Competitive and

Cost‐of‐Service pricing

WECC_AZ AZNM 5% 95%

WECC_IID AZNM 5% 95%

WECC_NM AZNM 5% 95%

WECC_SNV AZNM 5% 95%

WEC_CALN CAMX 7% 93%

WEC_LADW CAMX 7% 93%

WEC_SDGE CAMX 7% 93%

WECC_SCE CAMX 7% 93%

WECC_SF CAMX 7% 93%

ERC_FRNT ERCT 88% 12%

ERC_GWAY ERCT 88% 12%

ERC_REST ERCT 88% 12%

ERC_WEST ERCT 88% 12%

MIS_WUMS MROE 1% 99%

MAP_WAUE MROW 7% 93%

MIS_IA MROW 7% 93%

MIS_MAPP MROW 7% 93%

MIS_MIDA MROW 7% 93%

MIS_MNWI MROW 7% 93%

SPP_NEBR MROW 7% 93%

NENG_CT NEWE 97% 3%

NENG_ME NEWE 97% 3%

NENGREST NEWE 97% 3%

WECC_ID NWPP 3% 97%

WECC_MT NWPP 3% 97%

WECC_NNV NWPP 3% 97%
Page 9

State of Retail

Regulation

IPM Region

Code

NEMS Region

Code

Deregulation Share

(%)

Cost‐of‐Service Share

(%)

WECC_PNW NWPP 3% 97%

WECC_UT NWPP 3% 97%

WECC_WY NWPP 3% 97%

MIS_LMI RFCM 10% 90%

MIS_INKY RFCW 64% 36%

PJM_AP RFCW 64% 36%

PJM_ATSI RFCW 64% 36%

PJM_COMD RFCW 64% 36%

PJM_West RFCW 64% 36%

SPP_KIAM SPSO 20% 80%

SPP_SE SPSO 20% 80%

SPP_SPS SPSO 20% 80%

SPP_WEST SPSO 20% 80%

S_D_AMSO SRDA 13% 87%

S_D_N_AR SRDA 13% 87%

S_D_REST SRDA 13% 87%

S_D_WOTA SRDA 13% 87%

MIS_IL SRGW 51% 49%

MIS_MO SRGW 51% 49% See Chapter 3.1 Model Regions of IPM Documentation for v.5.13. http://www.epa.gov/airmarket/progsregs/epa‐ipm/docs/v513/Chapter_3.pdf
Page 10

Figure 1. Summary of Competitive Retail Price Estimates at the Regional Level

Competitive Retail Power Price [mills/kWh] = (Competitive Generation Cost + Transmission Charge + Distribution Charge) 

Generation

TransmissionCharge[mills/kWh] (AEO)

DistributionCharge[mills/kWh] (

Energy Price

[mills/kwh](IPM)

CapacityCost[$/KW‐Year](IPM)

ReserveMargin(%)(IPM)

LoadFactor(IPM)

Dist. LossFactor(AEO)

Marginal Energy Cost and Capacity Cost {mills/kwh] = [(Marginal Energy Price + (Capacity

Price × (1 + Reserve Margin)) / (8.76 × Load Factor)]/ (1 – Distribution Los Rate) (Eq. 4)

Competitive Generation Cost [mills/kWh] = (Marginal Energy Cost+ Reliability Cost + REC Cost) × (1 + Tax Rate) (Eq. 3)

RPS REC Cost

[mills/kwh](IPM)
Page 11

Figure 2. Summary of Cost‐of‐Service Retail Price Estimates at the Regional Level

Generation

Transmissionmills/kWh(AEO)

Total Costs of

Generation =

∑Fuel, VOM,

Capital, CCS, REC

Transaction costs.

[Million Dollars]

(IPM)

Dist. LossFactor(AEO)

Cost‐of‐Service Retail Power Price [mills/kWh] = (Final Cost of Power Generation + Transmission Charge + Distribution 

Net Energy

for Load

[GWh](IPM)

Sales [GWh] = Net Energy

for Load × (1‐Dist Loss

Factor)

Avg Cost of Power Sales [mills/kWh] = Sum of all

IPM Costs / Elec. Sold × 1000

Depreciation Costs

[mills/kwh] (AEO)

Final Cost of Power Generation [mills/kWh] = (Ave Cost of Power+ Depreciation Costs + Return + Final NUG Cost) × (1+ Tax Rate) (EQ. 6)

NUG Adder[mills/kWh](AEO)

Estimate of AEO

2013 New UnitCapital Costs post

2012

Final NUG Cost = (NUG Adder ‐ Estimate of post

2012 AEO 2013 New Unit Costs