Rulemaking No.: R.14-07-002 Exhibit No.: SCE-01 Witnesses: Reuben Behlihomji Gary Barsley

(U 338-E)

Southern California Edison Company’s (U 338-E) Corrected Opening Testimony

Before the

Public Utilities Commission of the State of California

Rosemead, California September 21, 2015

SCE-01: Southern California Edison Company’s (U 338-E) Opening Testimony

Table Of Contents

Section Page Witness

-i-

I.  INTRODUCTION .............................................................................................1 R. Behlihomji 

II.  BASIS FOR SCE’S PROPOSED GRID ACCESS CHARGE ..........................2 

A.  Background ............................................................................................2 

B.  Cost Drivers of Distribution and Transmission Costs ...........................4 

1.  Analysis of Pre- and Post-Solar Customer Demands ................6 

2.  Marginal Distribution Cost Component of GAC .....................10 

3.  Transmission and New System Generation Charge Infrastructure Cost Components of the GAC ...........................13 

4.  Other Delivery Charge (PPPC, NDC, DWRBC, and PUCRF) Cost Components of the GAC ..................................14 

C.  Calculation of the GAC .......................................................................14 

III.  PROPOSED INTERCONNECTION CHARGES FOR INTERCONNECTION FOR SMALL SYSTEMS .........................................19 G. Barsley 

A.  Background ..........................................................................................19 

B.  The Source of the Interconnection Cost Data Reported in Advice Letter 3239-E ...........................................................................19 

C.  Calculation of the $75 Interconnection Application Fee .....................21 

Appendix A Witness Qualifications and Prepared Testimony ........................................ 

Appendix B Summary Tables Related To Basis for GAC .............................................. 

SCE-01: Southern California Edison Company’s (U 338 E) Opening Testimony

List Of Figures

Figure Page

-ii-

Figure II-1 Residential NEM Summer 2014 Peak Demands vs. Los Angeles Peak Temperature ...........................................................................................................................................8 

Figure II-2 Average Load Profiles of NEM customers on Annual System Peak Days Pre and Post-PV ...........................................................................................................................................9 

SCE-01: Southern California Edison Company’s (U 338 E) Opening Testimony

List Of Tables

Table Page

-iii-

Table II-1 SCE Residential Distribution Marginal Cost Calculation Underlying 2015 Retail Rates ..........................................................................................................................................12 

Table II-2 Calculation of Ratio of Delivered to Net Electricity (kWhs) All SCE Residential NEM Customers (2014 Data) ...........................................................................................15 

Table II-3 Estimated Displaced Energy (kWhs) SCE Residential NEM Customers .................................16 

Table II-4 GAC Derivation and Sensitivity Analyses ...............................................................................18 

Table III-5 Calculation of Interconnection Application Fee ......................................................................21 

1

I. 1

INTRODUCTION 2

On September 1, 2015, the Commission issued the “Administrative Law Judge’s Ruling 3

Setting Evidentiary Hearings And Setting A Schedule For Further Activities Prior To 4

Evidentiary Hearings” (ALJ’s Ruling). The ALJ’s Ruling limited the scope of the evidentiary 5

hearings to three issues and identified the parties responsible for submitting opening testimony: 6

1) The basis for projections of prices of rooftop solar installations that are different from those 7

used in the Public Tool (CALSEIA); 2) The basis for the investor-owned utilities’ proposed 8

charges in the successor tariff for interconnection of small systems (PG&E; SCE; SDG&E); and 9

3) The basis for any proposed demand charges, capacity fees, standby charges, access fees, use 10

charges, or other fixed charges for the successor tariff that are different from the assumptions 11

used in the Public Tool (NRDC; ORA; PG&E; SCE; SDG&E). In compliance with the ALJ’s 12

Ruling, SCE provides its opening testimony on issues 2 and 3.1 13

1 Witness qualifications are provided in Appendix A. Certain workpapers supporting SCE’s Grid

Access Charge (GAC) are provided in Appendix B. Other work papers supporting the GAC and workpapers supporting SCE’s $75 interconnection fee are available on the website SCE created for this proceeding and to which parties have access, available at: https://edisonintl.sharepoint.com/teams/LIMS O365/TDR. The site will work best if you use Internet Explorer. Parties that have not yet accessed the site will receive an invitation e-mail following service of this testimony. To receive notifications each time SCE uploads new discovery responses or work papers to the site, click the "Data Request Library" link on the left, then click “Library,” and select “Alert Me.”

2

II. 1

BASIS FOR SCE’S PROPOSED GRID ACCESS CHARGE 2

The purpose of this testimony is to explain (1) the basis for SCE’s proposed grid access 3

charge (GAC) of $3/kW-month of installed nameplate distributed generation (DG) capacity to be 4

applied to customers under a net energy metering (NEM) successor tariff, and (2) why that cost 5

is fair to both solar DG customers as well as non-participating residential customers. SCE’s 6

GAC only applies to residential renewable DG installations under SCE’s proposal for a 7

successor to the current NEM tariff (SCE’s Proposal). 8

A. Background 9

The purpose of SCE’s GAC, as applied to customer-sited renewable DG, is to recover a 10

portion of SCE’s distribution, transmission, and new system generation infrastructure costs and 11

other charges2 from DG customers who displace their purchases of electricity, thereby reducing 12

their contribution to cost recovery, through the installation of renewable DG. All revenues 13

produced by the GAC from renewable DG customers will be used in combination with the 14

volumetric delivery charges, current fixed service charges, and minimum charges collected from 15

all residential customers to recover SCE’s authorized delivery service revenues for residential 16

customers. While the revenues collected by the GAC are modest at current renewable DG 17

participation levels, SCE’s Proposal is a reasonable method to collect these avoided on-site 18

delivery charge revenues and to minimize cost shifting experienced by non-participating 19

customers.3 20

2 For purposes of calculating the GAC, SCE’s volumetric delivery rates include transmission,

distribution, new generation source charge (NGSC) and other charges including the nuclear decommissioning charge (NDC), Department of Water Resources Bond Charge (DWRBC), and public purpose programs charge (PPPC). The GAC calculation does not include the Conservation Incentive Adjustment (CIA) component of SCE’s residential delivery rates. By continuing to apply the CIA as a volumetric rate component to displaced energy for NEM customers, instead of a fixed charge, all NEM customers (bundled service or DA) will see the same conservation price signal.

3 SCE proposes to update the GAC in future General Rate Case (GRC) rate design proceedings.

3

Under SCE’s current residential default tiered-rate structure and optional TOU tariffs, 1

nearly all of SCE’s transmission and distribution (T&D) revenue requirements as well as other 2

delivery-related revenues, such as revenues collected by the NDC, NSGC, PPPC, and DWRBC, 3

are recovered through volumetric delivery charges. The current NEM tariff permits residential 4

renewable DG customers to avoid paying volumetric charges for on-site displaced deliveries that 5

would otherwise collect these revenues. As a result, these revenues are primarily collected from 6

other non-participating residential customers in order for SCE to recover its residential delivery 7

revenue requirement. 8

There is a design demand and a resulting cost for the T&D infrastructure required to meet 9

each customer’s connected load or NCP demand, with the cost of that infrastructure at times 10

expressed as an average monthly cost of service. As discussed in Section II.B, data and analyses 11

support SCE’s conclusion that renewable DG customers continue to have about the same level of 12

NCP and 12-CP demands—the recognized cost drivers for recovery of distribution and 13

transmission service costs for SCE’s residential customers—after installation of renewable DG 14

that they had prior to DG installation. The data also show that DG customers have significantly 15

higher demands than residential customers as a whole and that their demands increase with 16

increasing temperature, just like other residential customers. Therefore, with the installation of 17

DG systems, the customer’s average monthly cost of service remains the same but the DG 18

customer’s contribution to T&D infrastructure cost recovery is reduced under the current NEM 19

tariff.4 The GAC is intended to balance this inequity by assessing a fixed charge designed to 20

recover the DG customer’s average cost of service related to on-site displaced deliveries, with 21

the balance of T&D costs recovered through volumetric delivery charges paid by all residential 22

customers. 23

4 The average usage (measured as electricity deliveries) of residential DG customers prior to installing

a solar DG system is about 1,114 kWh per month and, average net usage after DG installation is 549 kWh per month.

4

Section II.B also discusses the marginal cost drivers for recovery of distribution and 1

transmission costs and why the Commission has found that volumetric rates do not properly 2

capture the recovery of grid infrastructure costs for facilities sized to meet customers’ peak 3

demands. Renewable DG customers are indistinguishable from the general body of residential 4

customers in terms of establishing cost responsibility for T&D demand and should continue to 5

pay the share of SCE’s T&D costs that they avoid under the current NEM tariff. It also describes 6

how SCE’s proposed GAC would appropriately recover the delivery charges avoided under the 7

current NEM tariff by DG customers for distribution, transmission, and NSGCs as well as other 8

components of SCE’s delivery charges based on the estimated displaced electricity that results 9

when a customer installs DG. 10

Section II.C. provides the calculation of SCE’s proposed GAC based on the discussion in 11

Section II.B and includes two other sensitivity assessments, which would support a higher GAC 12

that SCE considered in proposing its GAC of $3/kW-month of installed nameplate DG capacity. 13

B. Cost Drivers of Distribution and Transmission Costs 14

In general, the California Public Utilities Commission (Commission) establishes rates for 15

customers or sub-groups of customers based on the marginal cost of serving such customers 16

adjusted, as required, to recover the utility’s revenue requirement through retail rates. The 17

primary cost driver for marginal distribution costs is the NCP demand of each of the customer 18

groups because most distribution costs are related to facilities needed to equip the grid to meet 19

peak demands of each rate class. SCE’s distribution revenue requirement is allocated to rate 20

classes in proportion to the sum of maximum monthly NCP demands, the sum of maximum kW 21

demand for the year for distribution, and forecast sales.5 For allocation of SCE’s transmission 22

revenue requirement, the 12-month coincident peak demand of rate classes is used. 23

5 Distribution cost allocation also reflects the Effective Demand Factor (EDF) that accounts for each

customer’s contribution to the peak load of the circuit from which it is being served. Higher EDF values for a particular rate class mean that more of SCE’s distribution revenue requirement would be allocated to that rate class because that rate class contributes more to the system or circuit peak demand.

5

After allocation of these distribution and transmission revenue requirements through the 1

rate design process, residential customers served on default tiered rates or optional TOU rates 2

pay rates to collect these revenues—predominantly volumetric rates. However, in a recent 3

decision, D.15-08-005, the Commission confirmed that volumetric rates do not properly capture 4

infrastructure costs for facilities sized to meet customers’ peak demands. 5

Capacity-related costs are the result of the infrastructure such as generators, 6 transmission lines, substations, circuits and final line transformers that must be put in 7 place so that electricity can be generated and distributed to customers. These 8 infrastructure costs are not driven by kWh sales volumes. Instead, facilities must be 9 sized so that they are sufficient to meet each customer’s kW demands during all time 10 periods, including those periods in which demand is the highest. Because kW 11 demand, not kWh usage, is the driver of these costs, volumetric rates (i.e., rates in 12 units of cents per kWh) do not properly capture these costs.6 13

D.15-08-005 specifically evaluated and compared the use of all volumetric rates, a 14

position advocated by solar parties, to PG&E’s proposed addition of demand charges to the same 15

PG&E non-residential tariff. The Commission agreed with PG&E’s testimony that average 16

distribution costs that are rolled into volumetric rates “remain uncollected when solar production 17

supplants usage” and that “[t]his makes volumetric TOU rates a poor choice for collecting non-18

coincident distribution costs.”7 The same logic also applies to SCE’s proposed GAC, which is a 19

fixed rate component, but is less complicated than demand charges, and is intended to recover a 20

portion of SCE’s capacity or demand costs that do not vary with displaced consumption of DG 21

customers because these costs are not collected through residential volumetric rates for DG 22

customers when solar generation supplants on-site usage. 23

In general, demand charges are intended to ensure that customers bear a reasonable share 24

of costs driven by the contribution of their peak demand to the peak demand on SCE’s 25

transmission and distribution system. Because residential retail rates are nearly exclusively 26

volumetric, SCE proposed the GAC as a demand charge proxy for the recovery of transmission 27

and distribution costs for residential DG customers. While demand charges are a more 28

6 D.15-08-005, p. 32 (emphasis added).

7 D.15-08-005, p. 28.

6

economically efficient means of recovering facilities-related costs, absent grouping NEM 1

customers in their own rate class separate from other residential customers for cost studies, SCE 2

has chosen to implement the GAC as a more understandable and more stable means of achieving 3

the same result. 4

1. Analysis of Pre- and Post-Solar Customer Demands 5

SCE proposes to assess the kWhs of delivery service that are, on average, avoided 6

or displaced through the installation of on-site renewable DG, the corresponding decrease in 7

delivery service revenues based on displaced on-site usage, and how to collect those same 8

revenues through a fixed GAC that is based on the nameplate capacity of the installed DG 9

facility. As part of its assessment, SCE considered whether there were other relevant cost 10

considerations that would mitigate against use of this approach, examining the effect of solar DG 11

installations on the peak demand of residential customers, as well as concerns that reductions in 12

usage related to solar DG installations should be treated the same as reductions in usage due to 13

energy efficiency. 14

While the average net usage for renewable DG customers declines after their DG 15

systems are installed, these renewable DG customers still impose distribution and transmission 16

costs on the grid that are similar to those they imposed on the grid prior to the installation of 17

solar DG. This is because grid facilities remain necessary for SCE to serve peak loads of DG 18

customers when their DG installation is not generating electricity or when their on-site usage is 19

greater than the output of their generator. 20

To assess the impact of DG customers on residential NCP demand, SCE 21

conducted a correlation analysis of average daily peak demand of NEM and all residential 22

customers during the summer versus the maximum temperature at the Los Angeles civic center 23

for a random sample of 1,000 SCE residential NEM customers. That analysis shows that the 24

daily average peak demand of SCE’s residential NEM customers is highly correlated to the daily 25

maximum temperature, with a statistically significant correlation coefficient of 0.89. The peak 26

demands of all residential customers, in general, are also highly correlated to the maximum 27

7

temperature, with a correlation coefficient of 0.88, but the average peak demand of NEM 1

customers is considerably higher than average residential customers. Figure II-1, below, 2

illustrates the similarities in the rise in peak demands of NEM customers and other residential 3

customers with increasing maximum temperature as well as the difference in magnitude of the 4

peak demands, using summer 2014 data.8 5

8 Workpapers for Figure II-1 are available on the website SCE created for this proceeding:

https://edisonintl.sharepoint.com/teams/LIMS%20O365/TDR/_layouts/15/start.aspx#/SitePages/Home.aspx.

8

Figure II-1 Residential NEM Summer 2014 Peak Demands vs. Los Angeles Peak Temperature

SCE also assessed the effect of customer-sited DG on SCE’s distribution and 1

transmission grid by comparing the typical demand of a sample of 1,000 SCE NEM customers 2

before and after the installation of their DG systems. Figure II-29, below, illustrates this effect. 3

9 Workpapers for Figure II-2 are available on the website SCE created for this proceeding.

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0

5.5

6.0

6.5

70 75 80 85 90 95 100 105

Average Peak Dem

and (kW

)

Daily high at LA CC (deg F)

NEM All Residential

9

Figure II-2 Average Load Profiles of NEM customers on Annual System Peak Days

Pre and Post-PV

The pre-solar PV installation load curve shown in blue, above, illustrates the daily 1

demand of typical customers, who later installed renewable DG, on SCE’s system peak day in 2

2012. The post-solar PV installation load curve shown in gray illustrates the daily demands of 3

typical solar DG customers on SCE’s system peak day in 2014. The post-solar load curve 4

overlaps for the most part the pre-solar and post-solar curve from midnight until 6:00 AM. It is 5

lower than the pre-solar curve from 6:00 AM until 6:00 PM and is higher than the pre-solar 6

curve from 6:00 PM until midnight. 7

Figure II-2 shows that the peak demand of a typical solar DG customer occurs at 8

6:00 PM and persists (and increases to its highest point at 8:00 PM), which is at or nearly at the 9

same time as the CAISO net system peak load, allowing for differences in usage from 2012 to 10

‐3

‐2

‐1

0

1

2

3

4

5

6

3AM 6AM 9AM NOON 3PM 6PM 9PM MIDNIGHT

KWH

Pacific Standard Time (PST)

Annual System PeakDay (8/13/12) Pre‐PV

Annual System PeakDay (9/15/14) Post‐PVSCE Delivered EnergyAnnual System PeakDay (9/15/14) Post‐PVNet Energy Consumed

Based on a sample of 1,000accounts that installed PV in 2013 with at least 6 months of interval data in 2012 and 2014.

10

2014. However, the post-solar peak demand of these customers remains essentially at the same 1

level as the pre-installation peak. It does not reduce the pre-solar peak demand or the resulting 2

contribution of such demand to the distribution cost of service for residential customers. 3

Accordingly, the installation of customer-sited DG has no present impact on NCP demands and 4

thus no impact on the allocation of SCE’s distribution costs to the residential class. 5

Some parties claim that the decrease in NEM customers’ contribution to recovery 6

of distribution costs through reduced volumetric delivery charges should be treated no differently 7

than customers who reduce their usage through energy conservation measures. However, there 8

is an important difference between a higher-than-average usage customer whose electrical needs 9

must be met at any time to a customer who is continuously a low usage customer or a customer 10

who installs conservation measures resulting in permanent decreases in usage, which can result 11

in a material decrease in connected load. Permanent reductions in usage due to energy efficiency 12

reduce a customer’s NCP demand in a manner that allows the utility to account for that reduction 13

in system planning. In contrast as discussed above, onsite renewable DG does not always result 14

in a reduction of NCP demand. As a result, eligible customer-generators require the use of the 15

utility’s grid for periods when the renewable DG is operating at lower capacity, and provide grid 16

support during intermittent operations, sometimes at a moment’s notice. The utility must 17

therefore carefully balance the distribution grid with capacity to support customer-generators 18

when their renewable DG systems are not operating. 19

2. Marginal Distribution Cost Component of GAC 20

SCE’s demand-related costs generally reflect grid infrastructure costs such as 21

poles, distribution conductors, circuits, and transformers that are necessary to provide service to 22

customers. These facilities are sized to serve peak loads of customers and, once established, for 23

the reasons discussed above, generally do not vary with respect to a DG customer’s energy 24

consumption. This section describes the marginal distribution cost basis that underlies the 25

development of SCE’s proposed GAC, calculating the distribution marginal cost for SCE’s 26

residential rate class and establishing SCE’s residential distribution marginal costs. 27

11

Consistent with Commission cost of service design principles, SCE conducted a 1

residential rate class distribution marginal cost analysis in Phase 2 of SCE’s 2012 GRC. The 2

results of this marginal cost analysis ultimately affect how much of SCE’s authorized revenue 3

requirement is reflected in retail rates for each of SCE’s customer groups. 4

As summarized in Table II-1, SCE assessed the marginal cost of additional grid 5

capacity such as transformers, poles, conductors for SCE’s residential customers. After 6

adjusting the result of $117.60/kW-year for SCE’s line losses and residential class diversity 7

factors (designated by SCE as Energy Diversity Factors or EDFs), the distribution marginal cost 8

is $39.80/kW-year. SCE then calculated the sum of maximum monthly residential customer 9

NCP demands; the residential marginal cost revenue requirement; and forecasted the sum of 10

annual customer maximum demands. Multiplying the sum of NCP demands by the number of 11

residential customers produces SCE’s marginal demand distribution revenue requirement of 12

$1.024 billion. Dividing that total by the annual sum of maximum demands, 197,969,647 kW, 13

yields a unit marginal distribution rate of $5.20/kW-month, which is equivalent to a 14

3.5 cents/kWh marginal distribution cost rate at forecast annual sales for SCE’s residential 15

customers. 16

SCE does not employ residential demand charges and has fixed customer charges 17

established at a level significantly lower than SCE’s marginal cost-based levels, which are used 18

for purpose of revenue allocation. Therefore, SCE’s distribution unit marginal costs must be 19

increased for two reasons: (1) to recover most of SCE’s fixed customer costs through 20

volumetric distribution rates; and (2) to scale the marginal costs in order to develop retail 21

volumetric distribution rates that collect SCE’s retail revenue requirement. These steps, 22

including the development of retail delivery rates corresponding to SCE’s 2012 and 2015 retail 23

revenue requirements are illustrated in Table II-1, below. 24

12

Table II-1 SCE Residential Distribution Marginal Cost Calculation Underlying 2015 Retail Rates

The numbers in Table II-1 illustrate how SCE’s current retail distribution rate is 1

derived from SCE’s distribution marginal cost basis of $39.80/kW-year applied to the residential 2

rate class. SCE’s marginal cost basis applied to the residential class is primarily driven by the 3

non-coincident peak demand of an average residential customer. This average residential 4

customer uses 589 kWh per month, and has an average annual NCP of 5.6 kW.10 Based on 5

SCE’s sample size of 1,000 NEM customers, DG customers, in contrast, use on average about 6

1,114 kWh per month prior to DG installation and have an annual average NCP of 8.7 kW that 7

declines modestly to 8.1 kW after the installation of a DG system.11 While the average annual 8

10 Appendix B.

11 Appendix B.

Design Demand Subtransmission Primary Total

SCE Distribution marginal Costs ($/kw‐yr) $33.7 $83.9 $117.6

SCE Line Losses adjustment 1.06463 1.02343

SCE EDF for a residential customer 0.32 0.33

SCE Distribution marginal costs (w/EDF & losses) ($/kW‐yr) $11.5 $28.3 $39.8

Customer Costs ‐ 50/50 NCO/RECC Blend for allocation purposes

SCE Settled Marginal Customer Cost ($/Cust/ month) =  $9.64

Rate Design

Marginal Cost

Rev Req

Cost Based 

Rev req

2012 GRC Retail 

Rev Req

June 2015 Retail

Rev Req

Sum of NCP Demands Max kW 25,729,116                  25,729,116             25,729,116            

SCE Forecast Customer Count 4,278,085                    4,278,085               4,278,085               4,273,504             

SCE Forecast Retail Sales ‐ kwh 29,134,393,419          29,134,393,419     29,134,393,419     29,082,728,088   

Forecasted sum of Max kW 197,969,647                197,969,647          197,969,647         

Customer charge distribution revenue $494,760,527 $676,467,287 $42,901,769 $41,336,751

Design Demand distribution revenue $1,024,447,884 $1,400,688,703 $2,034,254,220 $2,133,799,078

Total SCE  Distribution Revenue Requirement $1,519,208,411 $2,077,155,989 $2,077,155,989 $2,175,135,829

$1.36726

Customer Charge ($/customer/month) $9.6 $13.2 $0.91 $0.94

Distribution ($/kwh) $0.03516 $0.04808 $0.06982 $0.07702

Transmission ($/kwh) $0.01205 $0.01227

PPPC ($/kwh) $0.01314 $0.00741

NDC ($/kwh) $0.00014 $0.00028

DWRBC ($/kwh) $0.00493 $0.00526

NSGC ($/kwh) $0.00218 $0.00986

PUCRF ($/kwh) $0.00024 $0.00024

13

NCP demand is modestly lower (8.1 kW versus 8.7 kW), on the day that the system peaks, as 1

depicted in Figure II-2, the NCP demand remains fairly the same or is modestly higher. The 2

facilities required to serve this nearly unchanged NCP are the same even after the installation of 3

the DG system. However, because the DG installation allows such customers to displace 4

consumption, they are able to avoid paying these facilities related costs currently recovered by 5

volumetric retail rates. These displaced revenues should be collected through SCE’s proposed 6

GAC as function of multiplying the on-site displaced consumption by the retail distribution rate. 7

SCE has estimated that distribution revenues recovered from DG customers prior to the 8

installation of the DG system are reduced by $10.24 per month and has therefore included this 9

displaced revenue in the calculation of the GAC. This value is derived by multiplying the 133 10

kWh of on-site displaced energy calculated in Section C, Table II-3 below, with the distribution 11

retail rate of $0.07702/ kwh. 12

3. Transmission and New System Generation Charge Infrastructure Cost 13

Components of the GAC 14

SCE allocates FERC-authorized transmission revenues and NGSC revenues to 15

rate classes based on the 12-month coincident peak load (12-CP) of each rate class. The average 16

demand of DG customers at the time of the 12-CP is nearly 20% higher (1.60 kW versus 1.34 17

kW) than the average residential customer.12 This would imply that the 12-CP impact on 18

transmission infrastructure cost allocation for NEM customers would be higher had they been 19

considered separately from the residential rate class. For purpose of transmission cost and 20

revenue allocation, SCE includes NEM customers in the residential rate class. Therefore, 21

transmission infrastructure costs would remain unchanged after the installation of DG systems. 22

NSGC is another form of grid infrastructure that is used for distribution grid reliability and 23

support. Cost recovery for NSGC is similar to the recovery of transmission and distribution 24

related costs and does not decline with the installation of a DG system. Thus, the transmission 25

12 Appendix B. The same NEM customers prior to DG installation had an average 12-CP of 2.66 kW in

2012. Their 12-CP tracks the all residential 12-CP but at a considerably higher level.

14

and NGSC revenues that support grid infrastructure should be recovered through the GAC. 1

These two rate components are also avoided by the displaced consumption of residential DG 2

customers--just like the distribution component of delivery is avoided--although SCE’s costs for 3

these services do not decline with DG installations. SCE estimates that transmission revenues 4

are reduced by $1.63 per month and NSGC revenues are reduced by $1.31 per month due to on-5

site displaced energy and has therefore included this displaced revenue in the calculation of the 6

GAC. These respective values are derived by multiplying the 133 kWh of on-site displaced 7

energy calculated in Section C, Table II-3 below, with the transmission retail rate of $ 8

0.01227/kWh and NSGC retail rate of $0.00986/kWh. 9

4. Other Delivery Charge (PPPC, NDC, DWRBC, and PUCRF) Cost 10

Components of the GAC 11

The PPPC, NDC, DWRBC and Public Utilities Commission Reimbursement Fee 12

(PUCRF) are charges that are generally applicable to all customers and should not be avoided by 13

DG customers. 13 The displaced consumption of DG customers allows them to avoid paying 14

these charges, thus shifting their share of these costs to non-participating customers. Therefore, 15

it is reasonable to recover these components of SCE’s residential delivery charges through the 16

GAC. SCE has estimated that other delivery charge revenues recovered from DG customers 17

prior to the installation of the DG system are reduced by $1.75 per month and has therefore 18

included this displaced revenue in the calculation of the GAC. This value is derived by 19

multiplying 133 kWh of on-site displaced energy calculated in Section C, Table II-3 below, with 20

the retail rate components of each of these revenue components as depicted in Table II-1. 21

C. Calculation of the GAC 22

To calculate the GAC, SCE determined the volumetric delivery costs a typical NEM 23

customer avoids by estimating what SCE defines as average on-site displaced usage or displaced 24

deliveries in kWh after installation of renewable DG. That on-site displaced energy is illustrated 25

13 The Commission established Schedule DL-NBC to ensure that customer generators continue to pay

their fair share of such costs—specifically, CTC, PPPC, and NDC.

15

in Figure II-2, above, and is the area between the gray and blue lines, which is the difference in 1

SCE energy deliveries before and after installation of PV solar for SCE residential NEM 2

customers. Because on-site displaced kWh usage is not directly measurable from interval meter 3

data, SCE developed two approaches to estimate the amount of on-site electricity usage typically 4

displaced through the installation of a renewable DG source. A third scenario has been included 5

purely as an illustration of the sensitivity of displaced energy to the value of the GAC. 6

An empirical method SCE developed was to use 2014 interval data for total delivered 7

kWh (Channel 1) and total exported kWh (Channel 2) for all of SCE’s residential NEM 8

customers to calculate a ratio of total delivered kWh to net delivered kWh (i.e., total delivered 9

kWh minus total exported kWh). This ratio of total delivered kWh to net delivered kWh for all 10

SCE residential NEM customers in 2014 was 1.79, as shown in Table II-2, below. 11

Table II-2 Calculation of Ratio of Delivered to Net Electricity (kWhs)

All SCE Residential NEM Customers (2014 Data)

To apply this ratio to determine on-site displaced usage following the installation of 12

renewable DG, SCE analyzed the effect of solar DG installations on kWh usage of residential 13

(A) (B) (C) = (A) - (B)Delivered - kWh Export - kWh Net - kWh

January 2014 58,162,896                16,956,224          41,206,672           

February 2014 42,627,456                16,315,837          26,311,619           

March 2014 43,403,392                24,979,458          18,423,934           

April 2014 44,360,262                37,856,672          6,503,590             

May 2014 46,724,118                39,268,059          7,456,059             

June 2014 58,527,072                39,240,665          19,286,407           

July 2014 82,421,968                34,430,100          47,991,868           

August 2014 89,124,192                27,887,818          61,236,374           

September 2014 98,704,526                30,850,829          67,853,697           

October 2014 86,739,658                31,649,732          55,089,926           

November 2014 53,821,203                23,216,308          30,604,895           

December 2014 80,282,927                23,169,246          57,113,681           

Annual 784,899,670              345,820,948        439,078,722        

Scaling Factor 179%

MONTH YEAR

16

customers before and after installation of solar DG and provides its results in Table II-3. SCE 1

compared the kWh usage of 8,652 residential accounts, which had a minimum of six months of 2

interval billing data in 2010 prior to installation of their solar DG systems, to their net kWh 3

usage in the post-PV installation period from April 2012 through March 2013. This comparison 4

showed that these customers on average had 1,114 kWh per month delivered prior to installation 5

of solar DG and 549 kWh per month net delivered after installation of solar DG. On average, the 6

total displaced kWhs after installation of solar DG is 565 kWh per month (1,114 kWh delivered 7

pre-solar minus 549 net kWh delivered post-solar). Applying the ratio of 1.79 (total delivered to 8

net delivered kWhs from Table II-2) to the average net deliveries of 549 kWhs, results in an 9

average of 981 kWhs of delivered energy after solar DG installation. This 133 kWh difference 10

between 1,114 kWh per month delivered kWhs prior to the installation of solar DG and 981 kWh 11

per month delivered kWhs after the installation of a solar PV system is an estimate of average 12

on-site displaced kWhs resulting from installed renewable DG. Total displaced deliveries of 565 13

kWhs after installation of solar DG are comprised of a combination of on-site displaced kWhs 14

and off-site export kWhs--133 kWh on-site displaced and 432 kWh off-site exports, i.e, the 15

difference between 565 kWh total displaced deliveries and 133 kWh displaced on-site.14 16

Table II-3 Estimated Displaced Energy (kWhs) SCE Residential NEM Customers

14 Because SCE’s Proposal includes an ECR, SCE excluded all export energy from its GAC calculation.

(A)  (B)  (C) = (B) ‐ (A) 

   Pre Solar kWh  Post Solar kWh Displaced Energy kWh 

With Netting  1114  549  565 

Scaling factor (Table II‐3)  1.79

Pre solar kWh  1114

With Netting Post Solar kWh  549 

Without Netting Post Solar kWh  981 

On‐Site Displaced Energy kWh  133 

17

The on-site displaced kWh deliveries for residential solar DG customers would have 1

produced delivery service revenues that would have been collected and applied to the recovery of 2

SCE’s overall residential revenue requirements. SCE’s proposed GAC is a method of using the 3

installed capacity of the customer’s solar DG facility to apply SCE’s delivery charges (for 4

distribution, transmission, and other costs) to the on-site portion of displaced kWh deliveries to 5

make other residential customers indifferent to the solar DG installation. 6

Under three scenarios, SCE estimated GACs of $3.0, $4.3 and $6.3/ kW-month, as 7

indicated in Table II-4, below. SCE proposes to use a conservative estimate of $3/kW-month in 8

an attempt to balance policy driven priorities with competing cost and economic driven 9

considerations. 10

Using the methodology described above to estimate on-site displaced electricity shown in 11

Table II-3, as shown in Scenario 1 in Table II-4, below, a DG customer’s responsibility for costs 12

associated with these displaced electric deliveries is calculated as the product of the 133 kWh of 13

on-site displaced energy (as determined in Table II-3, above) and the sum of all of SCE’s total 14

volumetric delivery rates. This displaced retail delivery revenue of $14.94 per month15 is then 15

divided by the nameplate rating of the typical solar DG system of 5 kW to produce an average 16

GAC of $3.0 /kW-month. 17

Scenario 2 in Table II-4 is another method of estimating on-site displaced kWh deliveries 18

for DG customers and provides an on-site displaced electricity result, using the delivered energy 19

amount from the load study sample group of NEM customers that is higher than the estimate in 20

Scenario 1. After installation of solar DG, system, the average delivered energy to a typical DG 21

customer was 833 kWh per month. Using the same average pre-solar DG delivery of 1,114 kWh 22

per month, and post-solar deliveries of 833 kWh from the load study sample, the on-site 23

displaced energy is 281 kWh. Scenario 2 has an implicit assumption that NEM customers 24

maintain a consistent level of consumption and total displaced energy. 25

15 The total of $14.94 per month is the rounded sum of distribution ( $10.24), transmission ($1.63),

NSGC ($1.31), and other delivery charges ($1.75).

18

Scenario 3 in Table II-4 depicts the sensitivity of the GAC to the level of on-site 1

displaced energy by assuming a higher capacity DG installation and lower on-site displaced 2

energy than in Scenario 2. Assuming that total displaced energy remains fairly constant a 10% 3

reduction in delivered energy changes the on-site displaced energy to 231 kWh from the 133 4

kWh indicated in Scenario 1. This results in displaced revenues of $25.9 per month. Further, to 5

account for this reduction in delivered energy, SCE also proportionately increased the system 6

size to 6.0 kW. This resulted in a GAC of $4.3/kW per month. Scenario 3 provides an 7

additional data point to depict the variability in the GAC to on-site displaced energy as a function 8

of the system size. 9

Table II-4 GAC Derivation and Sensitivity Analyses

Scenario 1 Scenario 2 Scenario 3

Pre solar delivered energy (kwh) 1114 1114 1114 a

Post Solar delivered energy (kwh) 981 833 883 b

On‐Site displaced energy (kwh) 133 281 231 c = a ‐ b

Export compensated (kwh) 432 284 334

On‐Site displaced  (kwh) 133 281 231

Gross Displaced Energy (kwh) 565 565 565 <= Held constant

Cost Shift or Displaced Cosst ‐ ($/ month) $14.94 $31.57 $25.92

d = c x rate 

factors

Typical system size (kW) 5 5 6 e

GAC estimate  ($/ kW ‐ month) $3.0 $6.3 $4.3 f = d / e

19

III. 1

PROPOSED INTERCONNECTION CHARGES FOR INTERCONNECTION FOR 2

SMALL SYSTEMS 3

A. Background 4

SCE’s Proposal includes a $75 application fee for customers applying to be served on the 5

successor tariff.16 This fee is significantly less than the typical $800 interconnection fee. The 6

basis of the $75 fee is the Net Energy Metering (NEM) interconnection-related cost data that 7

SCE collected for November 2013 through June 2015 pursuant to the Resolution E-4610 and 8

D.14-05-033 and submitted in Advice Letter 3239-E. SCE reported cost data in six categories. 17 9

If SCE’s interconnection-related costs change in the future, SCE’s Proposal requests that the 10

Commission revisit and adjust the application fee amount. 11

Advice Letter 3239-E set forth six tables reflecting the costs associated with the six 12

categories the IOUs detailed in Advice Letter 3062-E. To calculate the $75 interconnection fee, 13

SCE used only the data reflected Table (1) NEM Processing and Administrative Costs, Table (2) 14

Distribution Engineering Costs, and Table (3) Metering Installation/Inspection and 15

Commissioning Costs. 16

B. The Source of the Interconnection Cost Data Reported in Advice Letter 3239-E 17

As noted above, SCE only used the cost data reflected in Tables 1, 2 and 3 of Advice 18

Letter 3239-E to calculate the $75 fee. The costs SCE collected and reported in Advice Letter 19

3239-E represent actual costs, including actual recorded labor costs for personnel working 20

directly on the NEM interconnection applications, as well as non-labor material costs associated 21

16 SCE Proposal at p. 42.

17 In compliance with D.14-05-033, the IOUs jointly filed Advice Letter 3062-E on June 23, 2014 detailing the categories of interconnection costs that they would be reporting in six tables on September 19, 2014. The six tables of costs are (1) NEM Application Processing and Administration Costs, (2) Distribution Engineering Costs, (3) Metering Installation / Inspection and Commission Costs, (4) Facility Upgrade Costs, (5) Waived Interconnection Fees for Qualifying NEM-Paired Storage Systems, and (6) Refunded Interconnection Costs for Qualifying NEM-Paired Storage Systems. On August 1, 2014, the Energy Division issued a disposition letter approving Advice 3062-E with an effective date of July 23, 2014.

20

with meter change-outs identified with specific NEM projects. Because not every NEM 1

application results in costs being incurred in every category, each row in Tables 1, 2 and 3 2

reflects a unique number of NEM projects for which SCE incurred costs in that category. 3

Multiple organizations within SCE are involved in the processing and approval of NEM 4

interconnection applications and each was responsible for tracking and collecting cost data. 5

With respect to Tables 1-3, Revenue Services Organization (RSO) was responsible for tracking 6

and collecting the cost data reflected in Table 1; Distribution Engineering (TD-DE) and Service 7

Planning (TD-SP) were responsible for tracking and collecting the cost data reflected in Table 2; 8

and SCE Metering Services Organization (“MSO”) and TD-DE were responsible for tracking 9

and collecting the cost data reflected in Table 3. SCE’s Distributed Generation Programs group 10

in SCE’s Customer Service Organization coordinated the tracking and collection effort and then 11

compiled and aggregated the data for reporting. To monitor accuracy for the final report, in the 12

months between the filing of Advice Letter 3103-E and Advice Letter 3239-E, Distributed 13

Generation Programs required RSO, TD-DE, and MSO to provide it with monthly data. 14

To derive SCE’s actual labor costs associated with the activities detailed in Tables 1, 2 15

and parts of 3 of Advice Letter 3239-E, SCE tracked the time they spent performing a specific 16

task and then assigned a monetary amount to that time by either using the employee’s actual 17

salary or the average salary of employees performing that category of work. Labor costs 18

included direct management and supervisory employee time, where applicable. To determine a 19

total labor costs per application, SCE added the labor costs together, divided by the total number 20

of applications SCE processed for which SCE issued a Permission to Operate (PTO) during the 21

reporting period. The costs reflected Advice Letter 3239-E’s Tables 1, 2, and 3 do not include 22

SCE’s 45.9% overheard markup. SCE similarly used the cost of labor and non-labor activities to 23

calculate the cost of activities set forth in Table 3. 24

Workpapers showing the data entry associated with these three tables are posted on 25

SCE’s discovery website. 26

21

C. Calculation of the $75 Interconnection Application Fee 1

SCE added the total aggregated cost amounts from Tables 1, 2, and 3 and divided that 2

sum by the number of completed NEM applications for which SCE issued a PTO processed 3

during the reporting period to arrive at a total cost per application. SCE then multiplied that 4

number by its 45.9% markup. Table III-5 reflects the calculation of SCE’s $75 application fee. 5

The actual fee is $73.89, which SCE rounded up to $75. 6

Table III-5 Calculation of Interconnection Application Fee

Table 1 Total Costs $2,098086

Table 2 Total Costs $705,081

Table 3 Total Costs $369,671

Total $3,172838

Divided by 62,647 $50.65 per application

Plus 45.9% Markup $73.89

Appendix A

Witness Qualifications and Prepared Testimony

A-1

SOUTHERN CALIFORNIA EDISON COMPANY 1

QUALIFICATIONS AND PREPARED TESTIMONY 2

OF REUBEN J. BEHLIHOMJI 3

Q. Please state your name and business address for the record. 4

A. My name is Reuben J Behlihomji, and my business address is 2244 Walnut Grove 5

Avenue, Rosemead, California 91770. 6

Q. Briefly describe your present responsibilities at the Southern California Edison Company. 7

A. I am currently the Manager of Marginal Cost and Forecasting within SCE’s Regulatory 8

Operations department. My current responsibilities include managing the Marginal Cost 9

and Forecasting function in Regulatory Operations. 10

Q. Briefly describe your educational and professional background. 11

A. I received a Bachelor of Engineering degree from the University of Mumbai in 1997 and 12

a Master of Business Administration from University of Southern California in 2003. I 13

have been employed by SCE since 2003. From 2003 to 2006, I worked in the 14

Transmission and Distribution business, first in the area of Power Delivery Technology 15

Integration and subsequently Substation Engineering. During that time, I gained an 16

understanding of Transmission and Distribution project design and execution coupled 17

with the process and procedures that went into transmission and distribution system 18

planning. In 2006, I joined the Controllers organization. In my tenure from 2006 to 19

2014, I managed three groups, namely the Valuation Services group, the Added Facilities 20

and Interconnection Facilities group, and the Non Energy Billing group. The Valuation 21

group was responsible for fixed asset valuation under various Annexation and 22

Condemnation proceedings, Department of Defense privatization and Base Realignment 23

projects and was responsible for assessing SCE’s base of insurable fixed assets. The 24

Added Facilities and Interconnection group was responsible for cost assessment and 25

reconciliation of special facilities projects for large retail customers and interconnection 26

A-2

facilities projects under FERC and CPUC-jurisdictional tariffs. The Non Energy Billing 1

Group was responsible for cost assessment and reconciliation of special facilities projects 2

for CALTRANS, Relocations and Rule 20 projects. In 2014, I joined Regulatory 3

Operations and assumed my current responsibilities as the Manager of the Marginal cost 4

and forecasting group. 5

Q. What is the purpose of your testimony in this proceeding? 6

A. The purpose of my testimony in this proceeding is to sponsor Sections I and II, which 7

discuss the basis for SCE’s proposed Grid Access Charge. 8

Q. Was this material prepared by you or under your supervision? 9

A. Yes, it was. 10

Q. Insofar as this material is factual in nature, do you believe it to be correct to the best of 11

your knowledge? 12

A. Yes, I do. 13

Q. Insofar as this material is in the nature of opinion or judgment, does it represent your best 14

professional judgment? 15

A. Yes, it does. 16

A-3

SOUTHERN CALIFORNIA EDISON COMPANY 1

QUALIFICATIONS AND PREPARED TESTIMONY 2

OF GARY BARSLEY 3

Q. Please state your name and business address for the record. 4

A. My name is Gary Barsley, and my business address is 1515 Walnut Grove Avenue, 5

Rosemead, California 91770. 6

Q. Briefly describe your present responsibilities at the Southern California Edison Company. 7

A. I am currently the Manager of Customer Distributed Generation programs within SCE’s 8

Customer Service department. My current responsibilities include managing the 9

customer incentive programs for customer distributed generation projects such as the CSI 10

and the SGIP, as well as the program management for the NEM (Net Energy Metering) 11

Interconnection tariff. 12

Q. Briefly describe your educational and professional background. 13

A. I received a Bachelor of Mechanical & Environmental Engineering degree from the 14

University of California at Santa Barbara in 1981 and a Master of Business 15

Administration from California State University Fullerton in 1989. I have been 16

employed by SCE during two different periods. I was employment by SCE from 1994 17

through 1998 in various groups related to transmission, substation, renewable energy, and 18

other power generation projects. I was then employed by SCE’s parent company, Edison 19

International (“EIX”), from 1998 to 2001. I worked in private industry outside of SCE 20

and EIX from 2001 through 2008. I returned to SCE in 2008 in my current position as 21

Manager of Customer Distributed Generation. In this role I am responsible for the 22

management of a group designed to support our customers and provide them with 23

information on DG technologies. Our programs allow SCE customers to participate in 24

programs designed to accelerate the adoption of distributed generation technologies. 25

A-4

Q. What is the purpose of your testimony in this proceeding? 1

A. The purpose of my testimony in this proceeding is to sponsor Section III, which discusses 2

the basis for SCE’s proposed NEM Interconnection Application Fee. 3

Q. Was this material prepared by you or under your supervision? 4

A. Yes, it was. 5

Q. Insofar as this material is factual in nature, do you believe it to be correct to the best of 6

your knowledge? 7

A. Yes, I do. 8

Q. Insofar as this material is in the nature of opinion or judgment, does it represent your best 9

professional judgment? 10

A. Yes, it does. 11

Appendix B

Summary Tables Related To Basis for GAC

B-1

NEM Non Coincident Peak (NCP) Demands (kW)

Month Pre‐solar NCP (kW) 

2012 Post‐solar NCP (kW) 

2014 

January  7.4  6.6 February  6.8  8.0 March  6.6  7.4 April  8.9  6.0 May  8.1  7.9 June  8.2  8.6 July  9.5  8.4 

August  9.1  8.4 September  9.0  8.2 October  9.4  8.2 November  6.5  7.9 December  6.6  7.4 

Annual  Average   8.7  8.1 

Residential Non Coincident Peak (NCP) Demands (kW)

Month NCP (kW) 2012 

NCP (kW) 2014 

January  3.9  3.2 February  3.8  3.2 March  3.8  3.2 April  4.1  3.5 May  4.1  4.2 June  4.3  4.1 July  4.7  4.6 

August  5.1  4.5 September  5.0  4.7 October  4.5  4.1 November  3.9  3.3 December  4.2  3.5 

Annual  Average   6.1  5.6 

B-2

Pre-Solar 12-CP comparison for delivered energy

PRE‐SOLAR (2012) NEM ACCOUNTS  ALL RESIDENTIAL ACCOUNTS IN 2012 

Date Demand (kW) 

hour (PST) 

Date Demand (kW) 

hour (PST) 

17‐Jan‐12  1.8  19  17‐Jan‐12 1.1 19

15‐Feb‐12  1.9  19  15‐Feb‐12  1.2 19

5‐Mar‐12  1.6  19  5‐Mar‐12 1.0 19

20‐Apr‐12  1.8  15  20‐Apr‐12  1.0 15

31‐May‐12  2.4  16  31‐May‐12  1.2 16

28‐Jun‐12  2.6  16  28‐Jun‐12  1.2 16

11‐Jul‐12  3.7  15  11‐Jul‐12 1.7 15

13‐Aug‐12  4.2  14  13‐Aug‐12  2.0 14

14‐Sep‐12  4.1  16  14‐Sep‐12  2.0 16

1‐Oct‐12  3.9  16  1‐Oct‐12 1.9 16

5‐Nov‐12  1.8  18  5‐Nov‐12 1.1 18

19‐Dec‐12  2.2  19  19‐Dec‐12  1.3 19

Average  2.7  Average  1.4 

NEM to Residential Ratio  1.9 

Post-Solar 12-CP comparison for delivered energy

POST‐SOLAR (2014) NEM ACCOUNTS  ALL RESIDENTIAL ACCOUNTS IN 2014 

Date Demand (kW) 

hour (PST)   

Date Demand (kW) 

hour (PST) 

15‐Jan‐14  1.5 18 15‐Jan‐14 0.9 18

20‐Feb‐14  1.6 19 20‐Feb‐14  0.9 19

5‐Mar‐14  1.6 19 5‐Mar‐14 0.9 19

30‐Apr‐14  0.5 16 30‐Apr‐14  1.0 16

15‐May‐14 1.6 16 15‐May‐14  1.7 16

30‐Jun‐14  1.3 16 30‐Jun‐14  1.4 16

24‐Jul‐14  2.3 16 24‐Jul‐14 2.0 16

1‐Aug‐14  1.7 15 1‐Aug‐14 1.8 15

15‐Sep‐14  1.8 14 15‐Sep‐14  2.0 14

6‐Oct‐14  1.8 16 6‐Oct‐14 1.4 16

6‐Nov‐14  1.6 18 6‐Nov‐14 0.9 18

15‐Dec‐14  1.9 18 15‐Dec‐14  1.1 18

Average  1.6  Average  1.3 

NEM to Residential Ratio  1.2