1 Application No: A.08-02-001
Exhibit No.:
2
Witness:
Jason Bonnett
3
4
)
5 In the Matter of the Application of San Diego Gas & )
6 Electric Company (U 902 G) and Southern California )
Gas Company (U 904 G) for Authority to Revise
)
)
7 Their Rates Effective January 1, 2009, in Their
Biennial Cost Allocation Proceeding.
)
8
)
A.08-02-001
(Filed February 4, 2008)
9
10
11
12
13
PREPARED DIRECT TESTIMONY
OF JASON BONNETT
14
15
SAN DIEGO GAS & ELECTRIC COMPANY
16
AND
17
SOUTHERN CALIFORNIA GAS COMPANY
18
19
20
21
22
23
24
25
26
27
28
BEFORE THE PUBLIC UTILITIES COMMISSION
OF THE STATE OF CALIFORNIA
October 6, 2008
1
TABLE OF CONTENTS
2
Page
3 I.
QUALIFICATIONS .................................................................................................. 1
4 II.
PURPOSE .................................................................................................................. 1
5 III.
SUMMARY ............................................................................................................... 1
6 IV.
COST ALLOCATION ............................................................................................... 4
7
A.
B.
8
9
10
C.
11
12
V.
CORE RATE DESIGN .............................................................................................. 6
A.
B.
C.
D.
E.
F.
13
14
15
16
17
Overview .......................................................................................................... 4
Non-Margin Costs ............................................................................................ 5
1.
Regulatory Account Amortizations ........................................................ 5
2.
SoCalGas Costs....................................................................................... 5
3.
Other Operating Costs............................................................................. 5
4.
Core De-Averaging ................................................................................. 6
Completed Revenue Requirements .................................................................. 6
G.
Residential Rates .............................................................................................. 6
Residential Baseline Allowances ..................................................................... 6
Submeter Credits .............................................................................................. 7
Liquefied Natural Gas Service Rates ............................................................... 7
Residential NGV Rates..................................................................................... 8
Core C/I Rates .................................................................................................. 8
1.
Consolidation of customer charges ......................................................... 9
2.
Elimination of seasonality in rates ........................................................ 10
NGV Rates...................................................................................................... 10
18
VI.
NONCORE RATE DESIGN ................................................................................... 11
19
Separate Rates for Transmission and Distribution Services ........................... 11
Noncore C/I Distribution Rates ...................................................................... 11
1.
Replacement of Noncore Transmission service .................................... 11
21
2.
Consolidation of customer charges ....................................................... 11
3.
Elimination of seasonality in rates ........................................................ 12
22
4.
Combining MPS and HPS rates ............................................................ 12
C. EG Rates ......................................................................................................... 12
23
VII. OTHER RATES ....................................................................................................... 13
24
A. Firm Access Rights (FAR) ............................................................................. 13
25
B. Public Purpose Program Rates ...................................................................... 13'
20
26
27
A.
B.
VIII. LRMC RATES ......................................................................................................... 14
APPENDICES A, B, AND C
28
-i-
1
PREPARED DIRECT TESTIMONY
OF JASON BONNETT
2
3 I.
QUALIFICATIONS
4
My name is Jason Bonnett. My business address is 8330 Century Park Court, San Diego,
5 California, 92123-1530.
6
I am employed by San Diego Gas & Electric Company (SDG&E) as a Principal
7 Regulatory Economic Advisor in the Regulatory Policy & Analysis Department of SDG&E and
8 Southern California Gas Company (SoCalGas). My primary responsibilities include analytical
9 support for rate design proposals prepared in regulatory rate filings and exhibits related to natural
10 gas proceedings before the California Public Utilities Commission (Commission).
11
I received a Bachelor of Science degree in Business Administration from Mankato State
12 University in 1992, a Juris Doctorate from Hamline University School of Law in 1995, and a
13 Master of Arts degree in Public Administration from Hamline University in 1997.
14
From May 1998 to July 2007, I was employed as a Public Utilities Rates Analyst by the
15 Minnesota Office of Energy Security with various responsibilities including: reviewing and
16 providing comments on natural gas utility filings on behalf of the Office of Energy Security
17 before the Minnesota Public Utilities Commission. In July 2007, I assumed my current position.
18 Since that time, I have performed analyses for the purpose of preparing advice letters before this
19 Commission.
20 II.
PURPOSE
21
The purpose of my testimony is to present SDG&E’s proposed natural gas transportation
22 rates. The proposed rates rely upon embedded cost (EC) principles for allocating SDG&E’s
23 authorized base margin costs among customer classes as shown in the prepared direct testimony
24 of Mr. Emmrich and Ms. Hom.
25 III.
SUMMARY
26
The proposed changes in SDG&E’s transportation rates are shown below in Table 1.
27 These are the class average transportation rates excluding the proposed charges for Firm Access
28
1 Rights (FAR). The FAR charge will be collected from core customers in the gas procurement
2 rate and from noncore customers through a separate bill.
3
4
Electric Generation
Present
$0.581
$0.290
$0.088
$0.037
System Total
$0.188
5 Residential
Core C&I
6 Noncore C&I
Table 1
Class Average Rates $/therm
Proposed
$ Change
$0.560
($0.021)
$0.276
($0.014)
$0.114
$0.026
$0.039
$0.002
% Change
(4%)
(5%)
30%
6%
7
8
9
$0.208
$0.020
11%
In order to obtain a comparable rate with present rates, Table 2 has the FAR charge
10 included in the proposed transportation rates.
11
12
13 Residential
Core C&I
14 Noncore C&I
Electric Generation
15 System Total
16
Table 2
Class Average Rates Including FAR charge $/therm
Present
Proposed
$ Change
$0.581
$0.565
($0.015)
$0.290
$0.281
($0.009)
$0.088
$0.119
$0.031
$0.037
$0.044
$.0007
$0.188
$0.213
$0.025
% Change
(3%)
(3%)
36%
20%
13%
The proposed rates reflect a decrease in the natural gas transportation revenue
17 requirement of $18,363,000 (approximately 6.8 percent). The primary drivers behind the lower
18 revenue requirement for SDG&E are distribution costs and regulatory accounts offset by an
19 increase in Company Use Fuel and unaccounted for gas (UAF).
20
Appendix A contains a complete set of rate tables using the embedded cost (EC)
21 allocation method which represents this proposal. This is the preferred case. Appendix B
22 contains a complete set of rate tables also using the EC allocation method; however, the present
23 revenue is derived using the present rate for each rate tier applied to the proposed volumes for
24 that tier. Appendix C contains a complete set of rate tables using the Long Run Marginal Cost
25 (LRMC) allocation method. This is the compliance case.
26
The rate results addressed herein are based on several inputs, including but not limited to
27 the proposed allocation of base margin costs to specific customer classes, the allocation of other
28 operating costs such as company-use fuel, the amortization of regulatory accounts to specific
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1 customer classes, and the class-specific demand forecasts sponsored by Mr. Emmrich. My
2 testimony completes the cost allocation process by adding the non-margin cost allocation results.
3 The cost allocation process utilizes various cost and demand forecasts to compute system
4 revenue requirements and allocates the revenue requirements among customer classes. The rate
5 design section of my testimony explains the development of specific unit charges to recover the
6 class-specific revenue requirements from customers based on proposed class throughput for the
7 cost allocation period.
8
The following lists the non-margin cost allocation and rate design proposals incorporated
9 in my testimony that are different from current practices. My testimony:
10
11
12
13
1) Reflects an EC allocation sponsored by Mr. Emmrich and Ms. Hom of
authorized base margin costs in effect on January 1, 2008.
2) Reflects a proposed throughput forecast for a three-year period, January 2009
through December 2011.
14
3) Reflects rates consistent with the Commission’s FAR decision (D.06-12-031).
15
4) Modifies the rate design for GN-3 customers by:
16

one; and
17
18
19
20
21
reducing the applicable number of monthly customer charges from three to

discontinuing the practice of charging seasonal rates.
5) Reflects a single set of “Sempra-wide” natural gas vehicle (NGV) rates
applicable to both SDG&E and SoCalGas as discussed by Mr. Schwecke.
6) Modifies the rate design for noncore (GTNC) customers by:
22

replacing transmission level service;
23

reducing the applicable number of monthly customer charges from six to
one;
24
25

discontinuing the practice of charging seasonal rates; and
26

replacing the current medium and high pressure system distribution level
27
service rates with a single set of rates for distribution level services.
28
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1
7) Proposes to have 100% fully de-averaged Core rates by the end of the 3 year
cost allocation period.
2
3
8) Reflects the recovery of transmission costs through a proposed transmission
4
level service (TLS) rate, which is applicable to all noncore customers of
5
SDG&E and SoCalGas served from the transmission system, regardless of
6
end-use, as sponsored by Mr. Schwecke. This rate provides noncore
7
customers served from the transmission system the option to choose either a
8
reservation or a volumetric rate. This rate is in addition to any FAR charges
9
incurred by a noncore customer.
10
9) Due to the proposed TLS rate, the “Sempra-wide” electric generation (EG)
11
rate applies to EG customers served from the distribution system. EG
12
customers served from the transmission system pay the proposed TLS rate
13
which is applicable to all customers of SDG&E and SoCalGas that are served
14
from the transmission system.
15 IV.
COST ALLOCATION
16
A.
17
Cost allocation is a two-step process where an overall revenue requirement is developed
Overview
18 and then allocated to specific customer classes. The revenue requirement broadly consists of two
19 primary cost categories, base margin and non-base margin (non-margin) costs. Base margin
20 costs include what is generally considered the utility’s authorized gas margin. The derivation
21 and allocation of SDG&E’s base margin cost among customer classes is sponsored by Mr.
22 Emmrich and Ms. Hom.
23
Non-margin costs (for ratemaking purposes) reflect other costs incurred by the utility to
24 provide basic transportation services to its customers during the forecasted cost allocation period.
25 These costs reflect, but are not limited to, regulatory account balance amortizations, core de26 averaging adjustments, and SoCalGas transportation and storage costs.
27
Except as noted in this testimony, the methods employed to develop and allocate non-
28 margin costs are consistent with the methods employed to develop the SDG&E transportation
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1 rates adopted in D.00-04-060, SDG&E’s most recent Biennial Cost Allocation Proceeding
2 (BCAP) decision.
3
B.
Non-Margin Costs
4
Non-margin costs are aggregated into the following four categories:
5

Regulatory account amortizations;
6

SoCalGas costs;
7

Other operating costs; and
8

Core de-averaging.
9
10
1.
Regulatory Account Amortizations
Mr. Roy explains in his testimony the forecasted balances of regulatory accounts
11 amortized into rates.
12
13
2.
SoCalGas Costs
The SoCalGas costs allocated to SDG&E reflected in the present application are
14 consistent with the figures shown in the prepared direct testimony of Mr. Lenart.
15
16
3.
Other Operating Costs
Other non-margin costs include, but are not limited to, UAF costs, and company-use gas
17 (CU) costs. Both UAF and CU costs are currently allocated to customer classes on an equal
18 cents-per-therm (ECPT) basis, using Average Year Deliveries as adopted in SDG&E’s most
19 recent BCAP decision (D.00-04-060). SDG&E proposes to change the ECPT UAF methodology
20 based on a UAF study sponsored by Mr. Emmrich. The total level of UAF costs is forecasted to
21 be substantially higher than UAF costs currently recovered in rates. This increase is due to a
22 substantial increase in the forecasted level of gas commodity prices proposed in this filing
23 relative to those adopted in the last BCAP decision. UAF costs are developed using a simple
24 calculation of UAF volumes multiplied by the utility’s forecasted gas commodity price for the
25 cost allocation period. Gas quantities and commodity prices estimated for UAF are discussed in
26 the Demand Forecast testimony of Mr. Emmrich.
27
SDG&E will continue to recover CU costs in the transportation rate. Gas volumes for
28 CU are discussed in the testimony of Mr. Emmrich.
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4.
1
2
Core De-Averaging
SDG&E’s residential and core C&I rates are currently 85.2% de-averaged. SDG&E
3 proposes to be 100% de-averaged by the end of the 3 year cost allocation period. The de4 averaging adjustment will be as follows each year of the cost allocation period:
5

Current = 85% de-averaged
6

Year 1 = 90.1% de-averaged
7

Year 2 = 95.1% de-averaged
8

Year 3 = 100% de-averaged
9
The proposal to be full de-averaged is being made in order to return to cost based rates.
10 The adjustment is being phased over the cost allocation period rather than in a single year in
11 order to maintain rate stability and less volatility in the residential and core C&I rates.
12
C.
Completed Revenue Requirements
13
The non-margin cost allocation results are added to the results of the base margin cost
14 allocation to complete the transportation rate revenue requirements. The completed
15 transportation revenue requirements becomes the starting point for rate design calculations.
16 V.
CORE RATE DESIGN
17
In this section, SDG&E updates its individual core tariff rates. This section describes
18 SDG&E’s proposed changes to current rate design methods.
19
A.
Residential Rates
20
Current residential rates consist of a two-tiered usage structure: baseline (BL) and non-
21 baseline (NBL) volumetric rates. In an effort to promote energy conservation, California Public
22 Utilities Code section 739.7 mandates that the NBL rate must be higher than the BL rate. The
23 current tier differential between SDG&E’s BL and NBL bundled rates is a factor of 1.19 (i.e., the
24 NBL rate is 19 percent higher than the BL rate). SDG&E proposes no change to the current tier
25 differential between SDG&E’s BL and NBL bundled transportation rates.
26
B.
Residential Baseline Allowances
27
SDG&E proposes no changes to baseline allowances in this proceeding.
28
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1
C.
Submeter Credits
2
Submeter credits apply to customers with a master meter that provides service to
3 residential sub-units (i.e., multi-family dwelling units and mobile home parks). SDG&E
4 proposes no changes to submeter credits in this proceeding.
5
D.
Liquefied Natural Gas Service Rates
6
SDG&E continues to provide liquefied natural gas (LNG) service to approximately 310
7 customers who are residents of the Roadrunner Mobile Home Park located in the desert
8 community of Borrego Springs. The current rate design consists of two monthly customer
9 facility charges, one for domestic use and the other for non-domestic use, and a single volumetric
10 rate. The current LNG rates, which are based on the methodology adopted in SDG&E’s 1996
11 BCAP (D.97-04-082), reflect a design where the average combined LNG and electric bill to
12 these customers would not exceed the average Borrego Springs area all-electric bill.
13
SDG&E proposes to retain the Commission-approved rates from the 1999 BCAP.
14 However, doing so will cause the average combined LNG and electric bill to exceed the average
15 Borrego Springs area all-electric bill. Therefore, SDG&E proposes that the Commission modify
16 its requirement that the average combined LNG and electric bill not exceed the average Borrego
17 Springs area all-electric bill. The rationale for SDG&E’s proposal is twofold:
18

the commodity price of natural gas has substantially increased over recent
19
years, which properly reflects the cost of providing utility natural gas
20
services to residential customers; while,
21

the electric residential rates for usage up to 130% of baseline were capped
22
pursuant to Assembly Bill (AB) 1X effective February 1, 2001, which
23
artificially understates the cost of providing utility electric services to
24
residential customers.
25
Since the 1999 BCAP decision, the wholesale price of natural gas has increased from
26 $2.60 per decatherm in the 1999 BCAP to a forecasted $7.66 per decatherm, almost a threefold
27 increase since the last BCAP. The wholesale price of natural gas has been fully deregulated (i.e.,
28
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1 not subject to price caps) since 1993. Finally, both the gas baseline and non-baseline rates reflect
2 the full cost of the wholesale price of natural gas.
3
Conversely, electric residential “bundled” rates for usage up to 130% of baseline were
4 capped pursuant to California Assembly Bill (AB) 1X effective February 1, 2001. In subsequent
5 rate proceedings, the Commission has authorized rate increases to residential electric rates except
6 for residential usage up to 130% of baseline.
7
SDG&E contends that the electric price caps for LNG services provided to Borrego
8 Springs customers distort the results from bill capping under the current LNG rate formula by
9 increasing the subsidy paid by all other residential natural gas customers who do not use LNG
10 services. SDG&E concludes that its natural gas customers, who, again, do not use LNG services
11 in Borrego Springs should not be penalized by paying a larger share of costs associated with
12 delivery of LNG to Borrego Springs. It would be illogical to further distort utility rates by
13 increasing this cost subsidy by artificially reducing the current charges under Schedule GL-1 in
14 order to bring the average combined LNG and electric bill below the average all-electric bill.
15
The methodology established by the Commission in the 1996 BCAP decision has been
16 rendered unmanageable by recent events. Therefore, SDG&E proposes:
17

to retain the Commission-approved rates from the 1999 BCAP; and
18

that the Commission eliminate the requirement for the average combined
19
LNG and electric bill to not exceed the average Borrego Springs area all-
20
electric bill.
21
The effect of this proposal is to allow SDG&E to maintain the current Commission
22 approved rate structure.
23
E.
Residential NGV Rates
24
SDG&E currently permits home refueling of natural gas vehicles through tariff page G-
25 NGVR. SDG&E does not propose to change the current rate design.
26
F.
Core C/I Rates
27
SDG&E has a single tariff serving its core commercial customers: Schedule GN-3.
28 Presently, the GN-3 rate design consists of three tiers of customer charges and seasonal three-
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1 tiered declining block volumetric rates. The Tier 1 rate applies to customers that use 1,000
2 therms or less per month. Tier 2 rates apply to customers using 1,001 to 21,000 therms per
3 month and Tier 3 rates apply to customers using in excess of 21,000 therms per month. The
4 winter season is defined as December 1st through March 31st and the summer season is from
th
5 April 1st through November 30 .
1.
6
7
Consolidation of customer charges
SDG&E proposes to consolidate its current series of three customer charges into a single
8 customer charge of $10 per month. Currently, GN-3 Tier 1 customers pay a $5.58 monthly
9 customer charge, Tier 2 customers pay an $11.16 monthly customer charge and Tier 3 customers
10 pay a $111.61 monthly customer charge.
11
There are two main reasons for the change in the GN-3 customer charge. The first reason
12 is simplicity. One customer charge is easier for a customer to understand than multiple charges.
13 Furthermore, since all customers in this class will have the same charge, this proposal will end
14 any debate (and possible gaming) over whether or not a customer qualifies for a particular
15 charge. The second reason is that the current tiered volumetric rate structure, in tandem with a
16 single customer charge, continues to provide a similar “cost-based” price signal as does the
17 current rate structure with multiple customer charges. This is particularly true for larger-use
18 customers. Since the same cost-based price signals are provided under either customer charge
19 structure, SDG&E proposes a rate structure that has the fewest, and least confusing, customer
20 charges.
21
In theory, customer charges reflect the recovery of utility customer-related costs such as
22 meter reading, bill processing, and related services. These costs are, in general, unaffected by
23 changes in customer usage. Accordingly, if the goal is to match cost causation with rate
24 recovery (i.e., cost-based rates), then all non-variable costs should be recovered through fixed
25 charges. Moreover, a larger-use customer typically has a bigger meter and regulator set than
26 does a smaller-use customer. A larger meter and regulator set may require more sophisticated
27 meter reading and maintenance relative to a smaller-use customer. This would result in a higher
28 fixed charge to a larger-use customer than a smaller-use customer.
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1
One way to achieve cost-based fixed fees is to have multiple customer charges, with
2 higher charges for higher-use customers. Another way to achieve the same thing is to have a
3 single customer charge with declining block rates. For larger-use customers, the initial tiered
4 rate effectively becomes another fixed fee because these customers will always consume
5 volumes in excess of the initial tiered usage block. This is not the case for smaller-use
6 customers. At a minimum, while a smaller-use customer will always pay the monthly customer
7 charge, the larger-use customer will always pay the monthly customer charge plus the first tiered
8 rate charge. Therefore, the larger-use customer will pay “fixed fees” that are generally larger
9 than the “fixed fees” paid by a lower-use customer under a rate structure that consists of a single
10 customer charge and declining block rates. Thus, the concept of cost-based recovery of customer
11 costs (i.e., larger per unit costs for larger use customers) is preserved under the proposed rate
12 structure.
2.
13
Elimination of seasonality in rates
14 SDG&E proposes to simplify core C/I rates by eliminating the seasonal difference in rates. A
15 single set of declining block rates is easier for the customer to understand.
16
G.
NGV Rates
17
SDG&E currently provides three types of “fully bundled” and “transport-only” NGV
18 services through tariff pages G-NGV and GT-NGV, respectively. The three types of services
19 are:
20

uncompressed gas;
21

compressed gas; and
22

co-funded stations.
23
Since there are no longer any co-funded NGV stations, SDG&E proposes to discontinue
24 the co-funded rate. SDG&E also proposes to create a set of “Sempra-wide” NGV rates (i.e., the
25 same tariff rates) applicable to both SDG&E and SoCalGas customers. Mr. Schwecke sponsors
26 the rationale for this proposal.
27
28
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1 VI.
NONCORE RATE DESIGN
2
In this section, SDG&E updates its individual noncore tariff rates. This section describes
3 specific changes to current rate design methods.
4
A.
Separate Rates for Transmission and Distribution Services
5
As discussed in the testimonies of Mr. Lenart and Mr. Schwecke, SDG&E and SoCalGas
6 propose a TLS rate for all noncore customers served from the transmission system, regardless of
7 end-use.
8
B.
Noncore C/I Distribution Rates
9
The current rate design consists of a series of six customer charges and seasonal
10 volumetric rates. Currently, there are three service level distinctions, medium-pressure
11 distribution service (MPS), high-pressure distribution services (HPS), and Transmission.
12
1.
Replacement of Noncore Transmission service
13 As discussed above, SDG&E proposes to replace noncore transmission service.
14
15
2.
Consolidation of customer charges
SDG&E proposes to consolidate its current six customer charges into a single customer
16 charge of $350 per month. There are two main reasons for this change. The first reason is
17 simplicity. A single customer charge is easier for customers to understand than six. Further,
18 because all customers in this class would have the same charge, this proposal will end any debate
19 (and possible gaming) over whether or not a customer qualifies for a particular charge. The
20 second reason is that the proposed rate structure, in tandem with the customer charge, provides a
21 similar “cost-based” price signal as does the current rate structure with six customer charges.
22 Since the same cost-based price signals are provided under either customer charge structure,
23 SDG&E proposes a rate structure that has fewer customer charges.
24
The 2006 usage profile of SDG&E’s GTNC customers revealed that most customers paid
rd th
th
25 customer charges associated with the 3 , 4 , and 5 customer charge tiers, with roughly 68
th
26 percent of the customers falling in the $338 per month 4 tier customer charge tier. As such, the
27 current six-tier customer charge structure contains some customer charges that in reality are not
28 appropriate for any existing or expected GTNC customer. The proposed customer charge of
- 11 -
1 $350 per month reflects a modest cost based relationship, because it is in the range of current
2 customer charges for GTNC customers and because it is similar to the customer charge that is
3 currently authorized by the Commission for use by SoCalGas.
3.
4
5
Elimination of seasonality in rates
The seasonal differentiation of rates is a carryover of the state-wide rate design
6 established in 1988 to recognize different seasonal usage patterns and the different costs that
7 reflected storage service provided. However, since the utility no longer provides bundled storage
8 services to noncore customers, this seasonal rate differentiation is no longer required or
9 constructive.
4.
10
11
Combining MPS and HPS rates
Combining MPS and HPS customers into a single rate simplifies the tariff rates and
12 addresses an anomaly of the current rate design that results in significant bill differences for
13 similarly situated customers due entirely to a service-level designation. There is a significant
14 discontinuity between the bills an MPS customer would pay and what a comparable (similar size,
15 operating equipment, load profile, etc.) HPS customer would pay for the same usage. This
16 difference is the result of whether or not the customer happens to be located near an MPS or HPS
17 hookup. Customers of similar usage located close to each other could pay very different rates
18 simply because one customer may be located next to an HPS instead of an MPS pipeline.
19
C.
EG Rates
20
Due to the proposed TLS rate, the proposed “Sempra-wide” EG rate would only apply to
21 EG customers served from SDG&E’s distribution system. No other changes are proposed to the
22 EG rate design other than it will apply to and will only be derived from EG customers served
23 from the distribution system.
24
EG customers served directly from the transmission system will pay the proposed TLS
25 rate which is applicable to all customers of SDG&E and SoCalGas that are served directly from
26 the transmission system.
27
28
- 12 -
1 VII.
OTHER RATES
2
A.
3
As discussed by Mr. Lenart, the FAR rate applies to all customers of SDG&E and
Firm Access Rights (FAR)
4 SoCalGas. The rate is consistent with the Commission’s FAR decision (D.06-12-031).
5
B.
Public Purpose Program Rates
6
While the Public Purpose Program (PPP) rate (i.e., G-PPPS) is no longer part of this
7 proceeding, the allocation of PPP costs among customer classes is. In this proceeding, SDG&E
8 proposes to remove the allocation of any costs comprising the G-PPPS rate from customer
9 classes that do not pay the G-PPPS rate. In the last BCAP, the Commission allocated certain
10 costs, such as Public Benefit Research Development & Demonstration program costs, to the EG
11 class. At that time, the PPP surcharge did not exist. PPP costs were recovered as part of gas
12 transportation rates. Pursuant to D.04-08-010, the Commission determined that PPP costs should
13 be recovered as a separate surcharge. Additionally, the Commission decided that EG rates would
14 be exempt from PPP surcharge rates. However, the Commission did not authorize a change in
15 the allocation of PPP costs among customer classes as set forth in SDG&E’s last BCAP decision.
16 Therefore, SDG&E currently has a situation where some PPP costs are being allocated to the EG
17 class but SDG&E is prohibited from recovering such costs from EG customers.
18
SDG&E’s proposal to remove the allocation of any costs comprising the G-PPPS rate
19 from customer classes that do not pay the G-PPPS rate will have minimal impact on the G-PPPS
20 rate for two reasons:
21

the $670,000 of costs currently being allocated to classes not paying G-
22
PPPS is minimal when compared to the $27,600,000 of total costs that are
23
currently allocated to the G-PPPS rate; and
24

this amount allocated to customers not paying G-PPPS rate is a “built-in”
25
under-collection in balancing accounts that is recovered from customers
26
that do pay the G-PPPS .
27
SDG&E’s proposal will allow SDG&E to correct a mismatch between the allocation of
28 PPP costs and the recovery of PPP costs from the various rate classes.
- 13 -
1 VIII. LRMC RATES
2
The compliance case is attached in Appendix C. These are the transportation rates
3 resulting from an allocation of base margin items using the LRMC allocation method. The
4 LRMC allocation of base margin is discussed by Ms. Hernandez and Ms. Smith.
5
This concludes my prepared testimony.
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APPENDIX A
Transportation Rate Tables
Preferred Case
APPENDIX B
Transportation Rate Tables
Present Revenue Shown as Present Rate * Proposed Volumes
APPENDIX C
Long Run Marginal Cost-Based Transportation Rate Tables
Compliance Case