BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA Application of Pacific Gas And Electric Company to Revise Its Electric Marginal Costs, Revenue Allocation and Rate Design. (U 39 M) Application No. 16-06-013 (Filed June 30, 2016) PACIFIC GAS AND ELECTRIC COMPANY 2017 GENERAL RATE CASE PHASE II FIXED COST METHODOLOGY REPORT, WORKPAPERS, AND PROPOSAL PRESENTATION Dated: November 21, 2016 CHRISTOPHER J. WARNER GAIL L. SLOCUM RANDALL J. LITTENEKER Pacific Gas and Electric Company 77 Beale Street, B30A San Francisco, CA 94105 Telephone: (415) 973-6695 Facsimile: (415) 973-5520 E-Mail: [email protected]Attorneys for PACIFIC GAS AND ELECTRIC COMPANY
Transcript
BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA
Application of Pacific Gas And Electric Company to Revise Its Electric Marginal Costs, Revenue Allocation and Rate Design.
(U 39 M)
Application No. 16-06-013 (Filed June 30, 2016)
PACIFIC GAS AND ELECTRIC COMPANY 2017 GENERAL RATE CASE PHASE II
FIXED COST METHODOLOGY REPORT, WORKPAPERS, AND PROPOSAL PRESENTATION
Dated: November 21, 2016
CHRISTOPHER J. WARNER GAIL L. SLOCUM RANDALL J. LITTENEKER
Pacific Gas and Electric Company 77 Beale Street, B30A San Francisco, CA 94105 Telephone: (415) 973-6695 Facsimile: (415) 973-5520 E-Mail: [email protected]
BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA
Application of Pacific Gas And Electric Company to Revise Its Electric Marginal Costs, Revenue Allocation and Rate Design.
(U 39 M)
Application No. 16-06-013 (Filed June 30, 2016)
PACIFIC GAS AND ELECTRIC COMPANY 2017 GENERAL RATE CASE PHASE II
FIXED COST METHODOLOGY REPORT, WORKPAPERS, AND PROPOSAL PRESENTATION
Pursuant to the Administrative Law Judge’s E-Mail Ruling Requesting Supplemental
Information dated November 16, 2016 in this proceeding, PG&E hereby files a stand-alone copy
of PG&E’s Appendix F, Fixed Cost Report, along with associated materials regarding PG&E’s
fixed cost methodology proposal. The Fixed Cost Report was served in this proceeding as an
appendix to PG&E’s Amended Testimony on September 30, 2016.
Dated: November 21, 2016
Respectfully submitted, By: /s/ Christopher J. Warner
CHRISTOPHER J. WARNER Pacific Gas and Electric Company Law Department 77 Beale Street, B30A San Francisco, CA 94105 Telephone: (415) 973-6695 Facsimile: (415) 973-5520 Email: [email protected] Attorneys for PACIFIC GAS AND ELECTRIC COMPANY
2. Collecting Fixed Costs Through Fixed Charges ......................................... F-6
3. Proposed Methodology for Estimating Fixed Costs and FixedCharges ..................................................................................................... F-7
a. Distribution ........................................................................................... F-8
b. Generation ......................................................................................... F-11
c. Public Purpose Programs .................................................................. F-12
d. Total Fixed Cost Estimate .................................................................. F-12
C. Treatment of Large and Small Customers ...................................................... F-12
D. Marketing, Education and Outreach Plans ..................................................... F-14
E. Proposed Workshop and Procedural Schedule .............................................. F-15
F. Conclusion ...................................................................................................... F-15
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PACIFIC GAS AND ELECTRIC COMPANY 1
APPENDIX F 2
FIXED COST REPORT 3
A. Introduction 4
Assembly Bill (AB) 327 restored to the California Public Utilities Commission 5
(CPUC or Commission) its traditional authority to align residential electric rates 6
with cost-of-service and cost-causation, including the authority of the 7
Commission to approve “new, or expand existing, fixed charges for the purpose 8
of collecting a reasonable portion of the fixed costs of providing electric service 9
to residential customers.”1 The Legislature’s action is consistent with the fixed 10
charges that for many years have been included routinely in water utility rates, 11
publicly-owned utility electric rates, and non-residential electric and gas rates 12
charged by Investor-Owned Utilities (IOU) in California. 13
Following the adoption of AB 327, the Commission staff has recognized the 14
importance of fixed charges in establishing equitable and cost-based rates: 15
Adding a modest fixed customer charge will better align residential rate 16 design with the principle of cost-causation and further reduce some of the 17 cross-subsidies in rates. Large users are paying a disproportionate share of 18 infrastructure costs through volumetric rates while small users are 19 underpaying.2 20
In their Phase 1 applications and testimony in the Residential Rate Reform 21
Order Instituting Rulemaking (RROIR), Rulemaking (R.) 12-06-013, Pacific Gas 22
and Electric Company (PG&E), Southern California Edison Company (SCE), 23
and San Diego Gas & Electric Company (SDG&E) each proposed that a fixed 24
monthly charge be implemented for residential electric rates, consistent with the 25
presence of such charges on non-residential electric rate schedules. In 26
R.12-06-013 and as authorized by AB 327, PG&E, SCE and SDG&E outlined 27
the benefits of collecting a portion of their fixed costs of serving residential 28
electric customers in a fixed monthly charge, including: 29
Better reflecting cost of service; 30
1 Public Utilities Code (Pub. Util. Code § 739.9(e). 2 CPUC, Energy Division Staff Proposal on Residential Rate Reform (May 9, 2014), at
http://www.cpuc.ca.gov/NR/rdonlyres/5278BEF7-F533-4ECF-95E0-50DD2B6B67E1/0/FINAL_ED_Staff_Proposal_RateReformforWeb5_9_2014.pdf, pp. 16, 84.
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Sending more accurate, cost-based price signals to customers; and 1
Mitigating the current inequities in residential electric rates, where the 2
collection of fixed costs in volumetric rates results in higher usage 3
customers bearing a disproportionately high share of these fixed costs 4
compared to lower usage customers. 5
Such fixed monthly charges for residential electric, gas, and water utility 6
customers are common in other states, employed routinely by publicly-owned 7
utilities in California like the Sacramento Municipal Utility District (SMUD), and 8
have been approved for investor-owned water utilities regulated by the 9
Commission.3 10
On July 3, 2015, the Commission issued Decision (D.) 15-07-001 in 11
R.12-06-013, finding that, “No party in this proceeding denies that utilities have 12
fixed costs, or the existence of customer-related fixed costs. Instead, the debate 13
centers on how the utilities should recover these fixed costs.”4 14
The Commission concluded in a 5-0 decision that, “A well designed fixed 15
charge representing a portion of the fixed customer-related costs to serve the 16
individual residential customer could be reasonable,”5 but that, “[a]dopting a 17
fixed charge at the same time as customers are also facing significant rate 18
impacts associated with tier flattening would be inconsistent with our statutory 19
duty to ensure reasonable rates.”6 The Commission ultimately determined that, 20
“A fixed charge should not be implemented until after the tier collapse is 21
complete and after default TOU has been implemented.”7 22
As further described in an Assigned Commissioner’s Ruling (ACR) dated 23
August 10, 2015:8 24
The Commission decided not to adopt new or increased fixed charges in 25 D.15-07-001, but instead established a process designed to ensure that any 26
3 See PG&E’s February 28, 2014 prepared testimony, Exhibit PG&E-101, pp. 2-11 to
2-13. 4 D.15-07-001, mimeo, p. 189. 5 D.15-07-001, Conclusion of Law (COL) 16. 6 D.15-07-001, COL 17. 7 D.15-07-001, COL 18. 8 Ruling of Assigned Commissioner issued by Commissioner Florio, page 2. Subsequent
to that Ruling, a change was made and President Picker is now the assigned commissioner.
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fixed charge that may be adopted in the future: (1) reflects appropriate 1 costs; (2) is calculated using a consistent methodology across utilities; and 2 (3) would be implemented after each utility has shifted to default TOU rates. 3
The August 10, 2015 ACR goes on to note that the process established by 4
the Commission provides that a workshop on fixed charges should take place in 5
a General Rate Case (GRC) Phase II proceeding of either PG&E, SCE or 6
SDG&E and that, pursuant to D.15-07-001, the issues for the workshops must 7
include: 8
1) Which fixed costs are appropriate to collect through a fixed charge? 9
2) Ensuring that any fixed charge amount treats small and large customers 10
fairly. 11
3) Timing of including new or increased fixed charges in residential rates. 12
4) Marketing, Education and Outreach (ME&O) for fixed charges.9 13
Subsequently, in an Administrative Law Judge’s Ruling dated November 5, 14
2015, the Commission directed that PG&E’s GRC Phase II proceeding, then 15
anticipated to be filed March 31, 2016, include within its scope a workshop 16
process to consider and develop a record to support a Commission decision 17
adopting categories of fixed costs in compliance with D.15-07-001. 18
In compliance with D.15-07-001, the purpose of this report is to support 19
PG&E’s application for Commission approval of the following: 20
The categories of fixed costs that are appropriate to collect through a fixed 21
charge in residential electric rates; 22
The methodology for calculating monthly fixed charges for residential 23
customers based on the approved fixed cost categories;10 24
Whether or not fixed charges should differ between small and large 25
customers;11 26
9 August 10, 2015 ACR, pp. 4-5.
10 This Commission-adopted methodology would be precedential for specific proposals made by PG&E, SCE and SDG&E in later, utility-specific, rate proceedings.
11 PG&E interprets this directive to mean that the workshops should address the extent to which fixed costs to serve small customers differ from those to serve large customers, not whether proposed fixed charges should be different for small versus large customers. This is not the proceeding in which the Commission is entertaining fixed charge proposals per se.
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The process for developing the plans for ME&O for fixed charges.12 1
In addition, as part of this proceeding and on a parallel with the other 2
Phase II rate design proposals in this proceeding, the Commission should set a 3
proposed procedural schedule for workshops in this proceeding that will provide 4
for collaborative input and comments on the proposed fixed charge methodology 5
and will develop an appropriate record to support a Commission decision 6
adopting categories of fixed costs in time to be incorporated into requests for 7
approval of new fixed charges in the IOUs’ 2018 Residential Rate Design 8
Window filings as required by D.15-07-001. 9
The remainder of Chapter 1 of this report is organized as follows. Section B 10
identifies the fixed costs of providing service to residential customers “not based 11
on the volume of electricity consumed,”13 including costs that do not vary with 12
usage as well as costs included in marginal cost analyses. In particular, it 13
describes not only marginal customer costs but also other categories fixed costs 14
of providing service, and it provides a conservative estimate of residential fixed 15
costs corresponding to about $54 per customer per month. Section C discusses 16
how the fixed charge amounts could account for different costs of serving large 17
and small customers. Section D presents a recommended procedural schedule 18
for workshops and written comments on the fixed charge methodology 19
proposals, including consideration of alternative methodologies. Finally, 20
Section E presents PG&E’s conclusions. 21
B. Residential Fixed Costs and Fixed Charges 22
1. Residential Fixed Costs 23
The Legislature, in enacting AB 327, defined “fixed charge” to include 24
traditional customer charges (assessed on a per-customer-month basis); 25
demand charges (assessed on a per-kilowatt (kW) basis); and any other 26
charge that does not vary with a customer’s consumption: 27
Fixed charge means any fixed customer charge, basic service fee, 28 demand differentiated basic service fee, demand charge, or other 29 charge not based upon the volume of electricity consumed.14 30
12 These plans will be vetted at the workshop (or workshops) to be scheduled after a
prehearing conference is held to determine the schedule. 13 Pub. Util. Code Section 739.9(a). 14 Pub. Util. Code Section 739.9.
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This language is consistent with a common-sense definition of 1
fixed costs as being comprised of all costs, regardless of function 2
(e.g., generation, distribution, etc.) or marginal cost category 3
(e.g., customer-related, demand-related, or energy-related) that do not 4
vary with the volume of electricity consumed. 5
The generation and delivery of electricity is a very capital-intensive 6
process, with large infrastructure requirements. PG&E incurs many costs 7
that are not accounted for when estimating marginal costs, because 8
marginal costs focus only on how costs change when one of three marginal 9
cost drivers—customers, demand, or usage—varies.15 But there are other 10
costs that are fixed because they do not vary with these marginal cost 11
drivers, like labor costs, office building costs (mortgage and rents), interest, 12
taxes, etc.16 Consequently, marginal cost revenues are an incomplete 13
category of fixed costs, fall well short of collecting PG&E’s total costs 14
(generally referred to as PG&E’s revenue requirement), and thus must be 15
adjusted upward during the revenue allocation process. This is done by 16
scaling marginal cost revenues by an Equal Percentage of Marginal Cost 17
(EPMC) multiplier (or factor), in order to ensure full cost recovery. This 18
situation, where marginal cost revenues are insufficient to recover the 19
revenue requirement, is sometimes described as one where marginal costs 20
fall below average costs. When this occurs, the fixed costs that remain 21
(i.e., the residual costs not covered by marginal cost revenues) must be 22
collected by some combination of monthly fixed charges, demand charges, 23
and energy charges.17 24
In addition, the costs of various programs recovered today via 25
non-bypassable charges do not vary with usage and are generally 26
15 These three cost drivers, customers (or customer-months), kW demands, and kilowatt-
hour (kWh) usage are the basis for estimating marginal customer costs, marginal capacity costs, and marginal energy costs, respectively.
16 For some of these items, PG&E’s marginal cost estimates do include, through the estimation of loaders, a small portion of costs associated with load growth-related capital investments. See Chapter 13 of PG&E’s marginal cost testimony, Exhibit (PG&E-2).
17 As the Office of Ratepayer Advocates has stated, in other parts of the country, regulators have approved fixed charges based on embedded costs rather than marginal costs.
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independent of the levels of the three marginal cost drivers. For example, 1
the costs of PG&E’s energy efficiency programs, currently collected through 2
the volumetric public purpose program (PPP) rate, are generally fixed 3
revenue requirements that must be collected each year independent of 4
customers’ actual demands or usage. The PPP revenue requirement does 5
not change when an additional customer is added, an additional kW of 6
demand is placed on the system, or an additional kWh is consumed. 7
2. Collecting Fixed Costs Through Fixed Charges 8
If fixed costs are collected through variable or volumetric energy 9
charges rather than through fixed charges, the result is a rate structure with 10
artificially high energy charges well in excess of marginal costs. This in turn 11
means that customers see inaccurate (and economically inefficient) price 12
signals, and for inclining block rate designs currently employed in California, 13
upper-tier users bear an inequitable share of PG&E’s fixed costs.18 14
Currently, PG&E’s residential electric rates have no fixed monthly charge or 15
demand charge. Thus the fixed costs embodied in the EPMC multiplier are 16
collected entirely in volumetric rates. This results in the burden of fixed cost 17
collection being borne disproportionately and inequitably by higher usage 18
customers, while lower usage customers avoid responsibility for paying their 19
equitable share of fixed costs. 20
Figure 1 presents an example which illustrates the situation. The solid 21
red line illustrates how customer bills would increase with usage if there is 22
no fixed monthly charge and a single volumetric charge of $0.20 per kWh, 23
while the dashed blue line shows the usage-bill relationship that would result 24
if, instead, all customers pay a portion of fixed costs via a $10 fixed charge 25
and the volumetric rate is lower, at $0.16 per kWh.19 The fixed charge 26
methodology if adopted should ensure that low usage customers pay a 27
cost-based share of fixed costs, while high usage customers, who under a 28
18 Artificially high volumetric rates, especially in the context of a tiered rate structure, can
lead to a “rate revolt” situation like the one that occurred in the Central Valley in 2009. It can also lead to high users simply bypassing PG&E’s system by installing on-site generation. The resulting sales decline and loss of revenue, in turn, puts even more upward pressure on volumetric rates.
19 For simplicity, this example assumes no tiers, but the same principle applies to tiered rates, where fixed charge revenue would be used to reduce the volumetric rate.
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purely volumetric rate design may pay a disproportionate share of those 1
fixed costs, will have their burden lessened. A monthly fixed charge if 2
designed properly would help alleviate a portion of the non-cost based 3
subsidy from high to low usage customers inherent in a strictly volumetric 4
rate design, and more equitably spread the fixed cost responsibility to all 5
customers. However, due to the statutory cap on the level of the fixed 6
charge, the subsidy, though mitigated to some extent, would remain. 7
FIGURE F-1 ILLUSTRATIVE EXAMPLE OF HOW BILLS VARY WITH USAGE
WITH AND WITHOUT A FIXED CHARGE
3. Proposed Methodology for Estimating Fixed Costs and Fixed Charges 8
PG&E’s proposed methodology for estimating residential fixed costs, 9
and the associated fixed monthly charges, focuses on three functionalized 10
revenue requirement or cost categories—distribution, generation, and 11
estimates for each of these three categories, based upon the revenue 2
allocation and marginal cost figures developed elsewhere in PG&E’s GRC 3
Phase II application. 4
TABLE F-1 PG&E RESIDENTIAL FIXED COSTS
AND FIXED CHARGES
a. Distribution 5
Focusing first on distribution, the portion of the distribution revenue 6
requirement allocated to residential customers is $1,914 million, as 7
shown in Column B of Table F-1. But the residential marginal 8
distribution cost, shown in Column F, is total just $1,473 million, leaving 9
a shortfall of $440 million of additional fixed costs (i.e., costs that do not 10
vary with any of the three marginal cost drivers) that need to be 11
collected, as shown in Column G. Focusing on the marginal cost 12
estimates, they are composed of customer-related costs (i.e., marginal 13
customer costs, shown in Column C) and capacity-related costs 14
(i.e., marginal capacity costs, shown in Column D). Column E shows 15
that none of the residential marginal distribution costs vary with kWh. 16
Column H shows total estimated fixed costs of distribution service, 17
calculated by summing the customer-related fixed costs in Column C 18
20 While not included in the table, PG&E also has other non-bypassable charge revenue
requirements (e.g., nuclear decommissioning, competition transition charges, California Department of Water Resources bond charges, etc.), some of which, too, are fixed costs in that their revenue requirements do not vary with usage.
and the additional fixed costs in Column G, yielding a residential class 1
distribution fixed cost estimate of $1,200 million. Although PG&E has 2
not done so in Table F-1, an argument can be made for also including at 3
least a portion of the capacity-related marginal costs, specifically the 4
non-time-varying capacity-related costs.21 These costs are driven by 5
customers’ kW demands, regardless of when those demands occur, and 6
not by energy usage; thus, a cost-based rate design would recover such 7
costs in kW demand charges. However, residential rates do not 8
currently have demand charges. Given that the costs are clearly not 9
energy-related, it may be appropriate to also include such costs in the 10
calculation of fixed costs, and then consider whether the costs should be 11
recovered through fixed monthly charges or volumetric dollar per kWh 12
energy charges (or some combination thereof).22 13
The marginal customer costs shown in Column C represent the 14
additional costs incurred by PG&E when a new residential customer is 15
added, and clearly should be included in estimating fixed costs. 16
Marginal customer costs are typically made up of two categories of 17
costs: (1) Revenue Cycle Services (RCS) costs; and (2) new customer 18
connection costs. The first cost category, RCS costs, includes the 19
following cost sub-categories: 20
Account Set-Up Costs – the costs to set up accounts when 21
customers start or change service at a new residence; 22
Meter Reading – the costs of reading meters, generally on a 23
monthly basis, including costs of collecting data remotely (or, in the 24
21 Marginal distribution capacity costs are composed of three items: (1) marginal primary
capacity costs, in units dollars per kW per year (where the kW are measured using PG&E’s peak-cost-allocation factors (PCAFs); (2) marginal secondary capacity costs, in units of dollars per kW per year (where the kW are measured at the final line transformer (FLT); and (3) marginal new business capacity costs, also in units of dollars per FLT kW. The first item, marginal primary capacity costs, make up the time-varying component of distribution capacity costs, and are most suitably collected in time-differentiated demand charges. The second two items, marginal secondary capacity costs and new business capacity costs, are not time-varying.
22 Of the $713 million in marginal distribution capacity costs, a total of $302 million are non-time-varying. So counting them as fixed would increase the estimated distribution fixed costs by $302 million, or about $5 per customer-month, over the amount shown in the table.
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case of those without SmartMeter™ devices, reading meters at the 1
customer’s location) and storing it so that bills can be calculated; 2
Billing and Payment – the costs of preparing and mailing paper bills, 3
including postage, and processing payments received; 4
Credit and Collections – the costs related to collecting amounts 5
owed by customers who pay late (net of amounts collected from 6
forfeited deposits and re-connection fees); and 7
Metering Services – the costs to maintain, test, and repair meters. 8
The second cost category, new connection costs, covers the cost of 9
hooking up new customers to the grid. New connection costs are 10
sometimes referred to as “TSM” costs, as they include the cost of (final 11
line) transformers, service drops, and meters.23 12
Column B of Table F-2 provides PG&E’s a breakdown of each of 13
these marginal customer cost items, in terms of dollars per customer-14
year.24 PG&E estimates the RCS component of marginal customer 15
cost to be $42.28 per customer-year and the new connection cost 16
component to be $117.67 per customer-year, for a total marginal 17
customer cost of $159.95 per customer-year. Column C divides each of 18
these figures by 12 to present them in units of dollars per customer-19
month. Finally, Column D multiplies Column C by PG&E’s forecast of 20
about 57 million customer-months to convert the marginal customer cost 21
estimate into an annual figure of $760 million. This figure is also shown 22
in Table F-1. 23
23 Note that SMUD also includes poles in its calculation of residential fixed costs used to
support its movement towards a $20 per customer-month fixed charge in 2017. SMUD’s fixed charge today is $18.
24 Details regarding these residential marginal customer cost estimates can be found in Chapters 7 and 8 of PG&E’s Marginal Cost testimony.
Turning now to the generation row in Table F-1, the portion of 2
PG&E’s generation revenue requirement allocated to residential 3
customers is $2,661 million, shown in Column B. The generation 4
marginal cost is composed of two components: 5
Marginal Generation Capacity Costs – the incremental cost 6
associated with adding a kW of generation capacity; and 7
Marginal Energy Costs – the incremental cost of serving an 8
additional kWh of energy.25 9
Marginal energy costs vary with customer usage by time-of-use 10
period, and are clearly not fixed costs. Marginal generation capacity 11
costs vary with kW demands and so would appropriately be collected 12
with demand charges. However, since residential customers do not pay 13
demand charges, an argument can be made some portion of these 14
costs would be appropriately collected in a fixed charge (or one which 15
varied in discrete increments based upon a customer’s maximum kW 16
25 There are no marginal customer costs of generation, as the number of customers is not
a direct driver of generation costs; rather, the driver is their aggregate kW demands.
[A] [B] [C] [D]
Marginal Customer CostsCosts
($/cust-yr)Costs
($/cust-mo)Costs
($ million/yr)
Revenue Cycle Services (RCS) Costs
Account Set-Up $8.59 $0.72 $41
Meter Reading $4.77 $0.40 $23
Billing and Payment $14.97 $1.25 $71
Credit and Collections $2.11 $0.18 $10
Metering Services $11.84 $0.99 $56
RCS Total $42.28 $3.52 $201
New Connection Costs $117.67 $9.81 $559
Total Marginal Customer Costs $159.95 $13.33 $760
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demand), rather than 100 percent through energy charges.26 In its 1
proposal here, though, PG&E has not included marginal capacity costs 2
in its estimate of fixed generation costs. Rather, those fixed costs 3
consist just of the additional fixed costs shown in Column G of $1,505 4
(this figure is also shown in Column H). 5
c. Public Purpose Programs 6
Finally, the PPP revenue requirement, which does not vary with 7
usage, is $354 million. There are no marginal costs associated with 8
PPP costs, so this full amount represents fixed costs, as shown in 9
Column H. 10
d. Total Fixed Cost Estimate 11
The fourth row of the table shows the total of distribution, 12
generation, and PPP revenue requirements and fixed cost estimates. 13
The total revenue requirement is $4,929 million, with estimated fixed 14
costs of $3,059 million. Dividing this fixed cost estimate by PG&E’s 15
estimated 57 million annual customer-months yields an average fixed 16
cost per residential customer-month of $53.67. 17
C. Treatment of Large and Small Customers 18
In Phase 1 of the RROIR proceeding, while not disputing that some portion 19
of fixed costs might not differ by customer size, PG&E proposed a simple fixed 20
monthly charge that would apply to all customers regardless of size (although it 21
would be lower for CARE customers).27 The Utility Reform Network (TURN), 22
however, recommended a size-related (or at least quasi-size related) proposal. 23
While TURN opposed fixed charges as its primary position, as a contingency in 24
the event that the Commission determined to implement new or increased fixed 25
charges, TURN proposed that households in multi-family (MF) dwellings receive 26
a 25 percent discount on their fixed charge relative to the fixed charge paid by 27
26 A detailed description of PG&E’s marginal generation capacity and energy costs can be
found in Chapter 2 of PG&E’s Marginal Cost testimony, Exhibit (PG&E-2). 27 See PG&E’s February 28, 2014 prepared testimony, Exhibit PG&E-101, Response to
Question 13, pp. D-22 – D-23.
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households in single-family (SF) dwellings. PG&E opposed that proposal, for a 1
variety of reasons summarized below:28 2
1) PG&E does not today have a reliable indicator in its billing system to 3
distinguish between SF and MF dwellers, and it would be expensive to 4
implement; 5
2) There would inevitably be many contentious disputes regarding how 6
individual customers in “gray areas” (e.g., duplexes, condominiums, etc.) are 7
classified; 8
3) If the Commission were to make such a distinction between SF and MF 9
dwellers with respect to the fixed charge, it should similarly distinguish 10
between them with respect to the baseline amounts; and 11
4) The reduction in fixed costs from MF dwellers resulting from a 25 percent 12
discount might not be able to be made up through a higher fixed charge on 13
SF dwellers, due to the caps set in AB 327. 14
As directed by D.15-07-001, this proceeding is not the designated 15
proceeding for considering and implementing fixed charge proposals, including 16
size-differentiated proposals. However, PG&E notes that, in determining 17
whether fixed costs of serving large versus small customers varies, it may be 18
prudent to classify customers into “large” and “small” categories based upon 19
each customer’s maximum non-coincident load during the prior calendar year. 20
PG&E has analyzed two years of new connection cost data from 2013 through 21
2014, and evaluated the relationship between these costs and customers’ 22
maximum annual non-coincident loads. Specifically, PG&E looked at 23
approximately 30,000 new residential connection jobs and grouped customers 24
by their maximum demand over calendar year 2015, as shown in Figure 1-2 25
below. The data show a significant increase in connection costs occurs between 26
2 kW and 4 kW. This suggests that a size-differentiated cut-off point of, say, 27
2.5 kW, could be used to categorize customers by size for purposes of analyzing 28
the fixed costs of serving the groups. Considerations persist, about how doing 29
such differentiation may be affected by the statutory dollar caps by CARE status 30
28 See PG&E’s October 14, 2014 rebuttal testimony, Exhibit PG&E-109, pp. 1-38 – 1-40.
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(as described in the bullet (4) above); however, this approach might still shed 1
light on differentiated costs by customers size.29 2
FIGURE F-2 RESIDENTIAL CONNECTION COSTS VERSUS ANNUAL MAXIMUM DEMAND
D. Marketing, Education and Outreach Plans 3
ME&O for fixed charges should be considered through a workshop process 4
to be determined after the PHC and in coordination with other ME&O 5
proceedings as appropriate. Careful evaluation of the appropriate level of 6
customer education and outreach for a specific rate element should be 7
contemplated along with other rate design changes, specifically default 8
time-of-use (TOU) rates. Any communication to customers about fixed charges 9
29 Flowing these changes through the rate design has many implementation/practical
challenges. For example, details would need to be worked out regarding how to categorize customers residing in newly-constructed dwellings, as well as customers without smart meters for whom hourly load data in the prior year are not available. Customers who move into a previously-occupied smart metered dwelling, though, would be assigned to a category based upon the highest load recorded at the premise during the previous calendar year. Each year, though, customers would be eligible for re-classification based upon their prior year’s maximum load.
