The Office of Ratepayer Advocates’ Report on Pacific Gas ......P.Sabino/R.M.Pocta OFFICE OF...

Docket Exhibit Number Commissioner ALJ Witness

: : : : :

A.17-09-006 ORA-05 C. Rechtschaffen S. Roscow P.Sabino/R.M.Pocta

OFFICE OF RATEPAYER ADVOCATES CALIFORNIA PUBLIC UTILITIES COMMISSION

The Office of Ratepayer Advocates’ Report on

Pacific Gas and Electric Company’s Gas Cost Allocation Proceeding

Cost Allocation and Rate Design

San Francisco, California June 6, 2018

TABLE OF CONTENTS

I. INTRODUCTION ..................................................................................... 1

II. SUMMARY OF RECOMMENDATIONS................................................... 2

III. DISCUSSION ........................................................................................ 13

A. THE COST ALLOCATION OF PG&E’S GAS DISTRIBUTION ........... 13

1. Description of PG&E’s Cost Allocation Proposal in Testimony ................................................................................... 15

2. ORA’s Analysis and Recommendation ....................................... 20

3. ORA Recommendation on Other PG&E Requests for Updates to Allocation .................................................................. 53

B. PG&E RATE DESIGN Proposals ....................................................... 57

1. Description of PG&E’s Rate Design Proposals in the GCAP Application ....................................................................... 57

2. ORA Recommendation on Baseline Season .............................. 59

(a) PG&E’s Proposal for a 3-Month Winter Baseline .................. 63

(b) PG&E’s Proposal Unnecessarily Increases Summer Baseline ................................................................................. 64

(c) GCAP Enhanced Tool Shows Disadvantages to Ratepayers ............................................................................ 68

(d) PG&E Concedes Its Proposal Could Increase Customer Bills But Explains the Goal Was to Reduce Bill Volatility ........................................................................... 70

(e) PG&E Has Not Explored All Options in Seeking to Respond to Senate Bill 711 and May Risk Possible Higher Yearly Customer Bill Totals If Its Focus Remains on Moderation of Excessive Bill Volatility Between November-December and February-March ............ 75

(f) ORA Recommends a Two-Month Off-Peak Winter Season .................................................................................. 79

3. ORA Recommendation on the Tier Ratio ................................... 84

(a) The Inverted Residential Tier Structure is Legislatively Mandated .......................................................... 85

(b) Historical Record Indicates Widening of Differential between Tiers 1 and 2. .......................................................... 85

(c) The Current Ratio of 1.41 is Excessive But May Be An Unintended Consequence of Market Dynamics & Some Forces Beyond PG&E’s Control .................................. 86

4. ORA Recommendation on Non-CARE Residential Minimum Transportation Charge Increase .................................. 88

(a) The Calculation of Monthly Non-CARE Residential Customer Costs ..................................................................... 88

(b) Customer Bill Impacts Show A Large Percentage of Non-CARE Residential Customers Could Experience As Much As a 35% Increase in Average Monthly Bills .......... 92

(c) ORA Results of the GCAP Enhanced Tool Scenario Runs ...................................................................................... 94

(d) PG&E Seeks Recovery of Gas Transportation Costs Beyond Fixed Customer-related Costs .................................. 96

5. ORA Recommendation on Super-User Charge .......................... 97

6. ORA Recommendation on Finding Reasonableness of Rates .......................................................................................... 98

7. ORA Recommendation to Incorporate the Most Recently Approved Future GT&S Throughput Forecasts Into The Then Effective GCAP Allocations in a Tier 2 Advice Filing. .......................................................................................... 99

8. ORA Recommendation on Future GCAPs ................................ 100

ATTACHMENTS ................................................................................................... 1

APPENDIX A ....................................................................................................... 29

1. Background on Marginal Cost and Embedded Cost Methodologies .............................................................................. 1

APPENDIX B ....................................................................................................... 12

WITNESS QUALIFICATIONS ............................................................................. 12

STATEMENT OF QUALIFICATIONS – PEARLIE SABINO ................................. 12

STATEMENT OF QUALIFICATIONS – ROBERT MARK POCTA ....................... 14

1

Cost Allocation and Rate Design 1

I. INTRODUCTION 2

This exhibit presents the analyses and recommendations of the Office of 3

Ratepayer Advocates (“ORA”) regarding the Cost Allocation and Rate Design 4

components of the Gas Distribution proposals of Pacific Gas and Electric 5

Company (“PG&E” or “Applicant”) in its Test Year (“TY”) 2018 Gas Cost 6

Allocation Proceeding (“GCAP”) in Application (A.) 17-09-006 dated September 7

14, 2017, as revised for Errata on February 15, 2018. The Scoping Memo of the 8

Assigned Commissioner and Administrative Law Judges, dated January 26, 9

2018,1 set forth the issues to be addressed in this proceeding. This exhibit 10

addresses the following issues included in the Scoping Memo: 11

3. Should PG&E be authorized to implement the cost allocation proposal set 12

forth in its testimony, using embedded costs, or should another 13

methodology be used to determine cost allocation? 14

4. Should PG&E's proposals for changing the residential winter baseline 15

months to December, January and February, and for placing the 16

remaining months of the year in a non-peak baseline season be 17

approved? 18

5. Should PG&E's proposal to reduce the residential Tier 1 and Tier 2 19

bundled rate differential to 1.2 over four years be approved? 20

6. Should PG&E's proposals regarding residential minimum transportation 21

charges be adopted: (1) a residential minimum transportation charge of 22

$15 dollars for non-CARE customer basic service; and, (2) a higher 23

super-peak minimum transportation charge of $45 for non-CARE 24

residential customers with daily peak usage of at least 15 therms? 25

7. Are the residential and non-residential gas rates proposed and the 26

expected rate and bill impacts that result from the implementation of 27

PG&E’s cost allocation and rate design proposals, and the cost allocation 28

methodology itself, just and reasonable, and if so, should they be 29

adopted? 30

1 Scoping Memo of Assigned Commissioner and Administrative Law Judges in A.17-09-006

dated January 26, 2018 (as amended on March 19, 2018 for a new procedural schedule), pp. 2-3.

2

13. Should the Commission adopt PG&E’s proposed schedule for submission 1

of future GCAP applications? 2

3

The remaining issues are addressed by other ORA witnesses in separate 4 exhibits. 5

II. SUMMARY OF RECOMMENDATIONS 6

1. Scoping Issue #3: Proposed Cost Allocation Methodology for 7 Revenue Allocation. 8

ORA recommends that the Commission deny PG&E’s request to migrate 9

to the embedded cost-based revenue allocation methodology2 as explained in 10

Section III.A. 11

2. Scoping Issue #4: Proposed Changes to the Baseline Season 12 Structure for Rate Design. 13

ORA proposes a peak winter season for the three months of December –14

February and an off-peak winter season for the two months of November and 15

March. ORA proposes no change to the current summer season or summer 16

baseline quantities. This policy and the proposed peak and off-peak winter 17

baseline quantities are explained and provided in Section III.B.2(f). 18

3. Scoping Issue #5: Proposed Phase-in Return of Residential 19 Bundled Tier Ratio. 20

ORA does not oppose PG&E's proposal to return the residential bundled 21

tier ratio to 1.2 and to achieve this goal through a phase-in of the reduction of 22

the residential Tier 1 and Tier 2 bundled rate differential to 1.2 over four years,3 23

as explained in Section III.B.3. 24

4. Scoping Issue #6: Proposed Increase to the Existing Non-CARE 25 Residential Minimum Transportation Charge and the Proposed 26 Creation of a New Super-Peak Second Tier Non-CARE 27 Residential Minimum Transportation Charge. 28

ORA disagrees with PG&E’s proposed 500% increase to the existing 29

non-CARE residential minimum transportation charge from $3 a month to $15 a 30

2 PG&E GCAP Testimony in A.17-09-006 dated September 14, 2017 (as Revised for Errata

dated Feb.15, 2018), p. 1-3.

3 PG&E GCAP Testimony in A.17-09-006 dated September 14, 2017 (as Revised for Errata

dated Feb.15, 2018),p. 7-2.

3

month, but does not oppose increasing the existing Non-CARE Residential 1

Minimum Transportation Charge.4 ORA recommends the Commission approve 2

a more reasonable marginal cost-based increase of an additional $1 a month, 3

representing a 33% increase from current levels, to raise the new Non-CARE 4

Residential Minimum Transportation Charge to $4 a month,5 from the existing 5

non-CARE Residential Minimum Transportation Charge of $3 a month,6 as 6

explained in Section III.B.4. 7

ORA does not conceptually oppose PG&E’s proposal to create a new 8

Super-Peak User Charge which will be a second tier Residential Minimum 9

Transportation Charge, but disagrees with the magnitude of the new charge. 10

ORA disagrees with PG&E’s proposal for a $45 a month Super-Peak User 11

Charge; and recommends a more reasonable marginal cost-based amount of 12

$12 a month for the Super-Peak User Charge.7 PG&E’s proposal for a Super-13

Peak User charge in the amount of $45 a month applies to non-CARE 14

residential customers who are identified as those with daily peak usage of at 15

least 15 therms.8 ORA also recommends that the super-peak user charge be 16

subject to periodic review and the identified customers in the top two percent be 17

appropriately informed before implementation that they may be subject to the 18

super-user charge. This issue is explained in Section III.B.5. 19

4 Id.

5 ORA GCAP Workpapers shown in the RD Model at Tab “Res_MinTranspChargeLevel” at cell

G26. PG&E’s proposal of $15 a month is shown right below it at cell G27.

6 Authorized and adopted in D.05-06-029 PG&E BCAP 2005, p. 5. FOF #2 states that a $3

minimum monthly transportation charge for residential customers would not create hardship for customers and recognizes that PG&E incurs costs even when a customer does not use any gas commodity.

7 Refer to ORA’s GCAP Workpapers shown in the RD Model at Tab

“Res_MinTranspChargeLevel” at cell O26. PG&E’s proposal of $45 a month is shown right below it at cell O27.

8 Id.

4

5. Scoping Issue #7: Whether the proposed residential and non-1 residential gas rates and the expected rate and bill impacts that 2 result from implementation of the ORA Recommendations 3 regarding PG&E’s Cost Allocation and Rate Design should be 4 adopted as just and reasonable. 5

ORA recommends the Commission adopt the residential and non-6

residential gas rates, and the expected rate and bill impacts that result from the 7

implementation of its recommendations on marginal cost allocation methodology 8

and rate design proposals, as discussed in Sections III.A and B. ORA presents 9

four summary tables. ORA Tables 5-1a and 5-1b provide a comparative 10

summary of the resulting revenue allocation numbers for its recommendation 11

which are marginal cost-based using the Discounted Total Investment Method 12

(DTIM)9 method and PG&E’s Proposed Gas Distribution Cost Allocation on the 13

basis of an Embedded Cost-based method.10 ORA reproduced in Attachment C 14

the Comparative Summaries of cost allocation methods, which are also shown 15

in PG&E’s GCAP testimony in Tables 3-4 and 3-5, based on the “current” 16

methodology, the marginal cost New Customer Only (“NCO”), the marginal cost 17

Rental Method (RM), and the embedded cost (EC) methodology.11 18

A background discussion on these methodologies is provided in 19

Appendix A of this exhibit following presentation of PG&E’s request in the GCAP 20

and ORA’s Analysis and Recommendation on the same. In Appendix A of 21

PG&E’s testimony, PG&E also provides a background discussion on the 22

marginal cost methodologies based on the NERA Regression method12 to 23

estimate the Marginal Distribution Capacity Cost (MDCC) and the Marginal 24

Customer Access Capacity (MCAC) cost. 25

9 Decision 92-12-058, which first adopted the Long Run Marginal Cost for California’s

respondent gas utilities, describes the other methods, including the DTIM, pp. 32-34.

10 Embedded costs are based on historical recorded costs while LRMC costs such as those

based on the DTIM are forward-looking costs.

11 Tables 3-4 and 3-5, PG&E GCAP testimony, pp.3-7 through 3-8.

12NERA stands for National Economic Research Associates Inc.

5

ORA’s final numbers for its Marginal Cost recommendations are DTIM-1

based, as shown in ORA Table 5-1a and 5-1b.13 ORA’s recommendation 2

incorporates ORA’s final throughput inputs in the RD model and capped 3

adjustments. ORA Table 5-1a shows that PG&E’s EC Proposal will result in 4

approximately $52 million more allocated to residential customers than those 5

under marginal cost. While PG&E’s EC Proposal shifts more allocation to 6

Residential customers, the EC Proposal and ORA’s recommendation will have 7

the same amount of allocation to small commercial customers. The PG&E EC 8

proposal will allocate slightly less to large commercial distribution and Core 9

NGV. The GNGV2 customer category will have the same amount of allocation 10

under both PG&E’s EC proposal and ORA’s recommendation. Overall, the total 11

Core customers will be allocated approximately $42 million more under PG&E’s 12

EC Proposal, while reducing the allocation to total noncore customers by 13

approximately $42 million. ORA Table 5-1b provides the same information in 14

terms of percentage share of the total. Total Core will be allocated 94.385% 15

under ORA’s recommendation while PG&E’s EC Proposal will allocate 96.746% 16

to total Core customers, or 2.361% more allocation to total Core under PG&E’s 17

EC proposal. 18

The same results presented in Table 5-1a are shown in Table 5-1b, but 19

the information in the latter shows the share of the total gas distribution revenue 20

requirement of each customer class in percentage terms instead of the amount 21

in US dollars of the total Gas Distribution Revenues as shown in Table 5-1a. 22

ORA Table 5–1b shows that under the PG&E proposed EC-based 23

allocation in column (c), Residential customers described at line 1 of the table 24

could bear 77.9 percent of the PG&E gas distribution revenue requirement, if 25

approved by this Commission. As shown in column (d) at line 1, the proposed 26

EC-based method would assign 2.9% more of the PG&E gas distribution 27

13

ORA verified certain PG&E responses in data request ORA-29, where PG&E’s data response to ORA presents a different approach to marginal cost than the NERA regression method. ORA obtained those responses from PG&E in its follow-up to data request ORA-29. ORA’s final recommendations are those shown in column “b.”

6

revenue allocation burden on Residential customers compared to the allocation 1

under ORA’s recommendation on the Marginal cost-based allocation shown in 2

column (b). In US dollar terms, ORA Table 5-1a shows under column (d) at line 3

1 that the difference between the two allocation methods would mean 4

approximately $52 million more in costs allocated to Residential customers, if 5

PG&E’s EC-based proposal were approved. Overall, all Core customers, which 6

include Residential, Small Commercial, Large Commercial Distribution, Core 7

NGV, and Compression Cost for G-NGV2 customers, could be allocated 8

2.361% more of PG&E’s gas distribution revenue requirements under PG&E’s 9

proposal, if approved by the Commission. In US dollar terms, this could be 10

approximately $42 million more of the cost burden on all Core customers. On 11

the other hand, NonCore customers could be allocated approximately $42 12

million less of the cost burden under PG&E’s proposal, as shown in Table ORA 13

5-1a at column (d) at line 11. 14

The total amount shown on line 12 of ORA Table 5-1a is PG&E’s gas 15

distribution revenue requirement, which is the subject of the allocation in the 16

GCAP.14 PG&E and ORA’s recommendations on line 12 are the same since 17

that amount was previously determined in the PG&E 2017 GRC Decision in 18

D.17-05-013 (in A.15-09-001).15 This GCAP will determine the amount of 19

PG&E’s gas distribution revenue requirement, adopted in D.17-05-013, 20

allocated to each customer class.16 21

ORA also presents in ORA Table 5-2a and 5-2b, the Comparative 22

Marginal Cost numbers as presented by PG&E in its GCAP testimony which 23

were used by PG&E for purposes of comparison. It is based on PG&E’s 24

Marginal Cost Adopted in 2005 and escalated to 2018.17 PG&E’s comparative 25

marginal cost makes use of PG&E’s throughput forecasts. 26

14

PG&E Response to data request ORA-03 Q.2(j).

15 PG&E Response to data request ORA-03 Q.2(j).

16 PG&E Response to data request ORA 03 Q.2(j).

17 PG&E Response to data request ORA 025 Q.1 subpart 3.

7

ORA Table 5-2a shows a summary of the Gas Distribution Cost 1

Allocation forecast results (in 2018 US Dollars) which compares PG&E’s 2

Marginal Cost Adopted in the 2005 BCAP, should the marginal cost 3

methodology be retained, and PG&E’s Proposal in 2019 for the cost allocation 4

of the Gas Distribution function.18 The scaled marginal cost revenue values 5

presented under column “b” for the PG&E Marginal Cost are based on the 6

marginal cost values presented by PG&E in its GCAP application. Since PG&E 7

obtained a negative coefficient on the MDCC value based on the NERA 8

regression, PG&E instead presented an alternative MDCC value under the 9

marginal cost approach as presented in the filed GCAP for purposes of 10

comparison.19 11

18

Chapter 3 of PG&E’s testimony presents the cost allocation results for Gas Distribution-Level Revenue Requirements based on the embedded cost method proposal. Chapter 6 of PG&E’s testimony shows different results because this portion shows the consolidated impacts of several PG&E proposals. Among others, the update to throughput, and the cost allocation results for Gas Distribution-Level Revenue Requirements in Chapter 3 as well as the adopted gas distribution-level Pension and Cost of Capital cases (see page 6-2). In addition, Chapter 6 consolidates the results of PG&E’s proposals which update the allocation of various gas transportation revenue requirements, namely, the Energy Efficiency (EE) and Energy Savings Assistance (ESA) programs, the update to the Electric generation (EG) California Public Utilities Commission (CPUC) fee (see page 6-1), the updates to the Core Brokerage Fee (CBF) and the G-NGV2 Compression Cost (see page 6-2). Please refer to Ex. ORA-03 on the EE/ESA for ORA’s recommendations on these proposals incorporated in PG&E’s Chapter 6 and to Section III.A.1 of this exhibit on the CBF and G-NGV2 and to Section III.A.3 of this Exhibit on the CPUC Fee.

19 Response to data request ORA-25 Q.01 part 3.

8

ORA Table 5–1a 1 Results of Cost Allocation: Gas Distribution Revenue Requirement 2

(in $ Thousands) 3 4

Ln No.

Description

(a)

ORA’s

Recommendation20

(b)

PG&E

Proposed21

(c)

Amount PG&E > ORA

(d = c - b)

1 Residential $1,339,657 $1,391,558 $51,901

2 Small Commercial 316,329 316,329 $0

3

Large Commercial:

Distribution

17,326

10,768

($6,558)

4 Uncompressed NGV1 7,987 4,793 ($3,194)

5 Compression Cost GNGV2 3,914 3,914 $0

6

Total Core

1,685,214

1,727,363

$42,149

7 Industrial Distribution 74,878 42,964 ($31,915)

8 Industrial Transmission 20,720 11,231 ($9,488)

9 Electric Gen 3,971 3,565 ($406)

10 Total Wholesale 680 341 ($340)

11 Total NonCore 100,249 58,100 ($42,149)

12 Total $1,785,463 $1,785,463 $0

Source: PG&E 2018 GCAP Workpapers Updated for Errata dated Feb.15, 2018 as shown in Excel file “Gas Revenue Allocation

Embedded Cost” at Tab “Output-RRQ Allocation.” ORA’s Recommendations on Marginal Cost numbers are shown in ORA’s

Workpapers for Marginal Cost NCO Scaled Marginal Cost Revenues as adjusted. See also Attachment C from PG&E’s 2018 GCAP

Workpapers Updated for Errata in Excel file “Base DistributionRev Allocation Comparison Errata 20180215” for Comparison

Allocation of Gas Base Distribution Revenue Requirement under Marginal Cost NCO and Rental Method, Proposed Embedded Cost,

and the Current (BCAP 2010 Settlement) Method.

5

20

Refer to ORA’s Workpapers for Marginal Cost NCO Scaled Marginal Cost Revenues. The MDCC calculation is based on the DTIM method at system level provided by PG&E in Response to data request ORA-29, Q.01.

21 PG&E 2018 GCAP Workpapers Updated for Errata dated February 15, 2018 as shown in

Excel file “Gas Revenue Allocation – Embedded Cost Feb15 2018 (Errata)” at Tab “Output – RRQ Allocation.”

9

ORA Table 5–1b 1 Results of Cost Allocation: Gas Distribution Revenue Requirement 2

(in Percent) 3 4

Ln No.

Description

(a)

ORA Recommendation

22

(b)

PG&E Proposed

23

(c)

Amount PG&E >ORA

(d=c-b)

1 Residential 75.031% 77.938% 2.907%

2 Small Commercial 17.717% 17.717% 0%

3 Large Commercial:

Distribution

0.970%

0.603%

-0.367%

4 Uncompressed NGV1 0.447% 0.268% -0.179%

5 Compression Cost

for G-NGV2

0.219%

0.219%

0.000%

6 TOTAL CORE 94.385% 96.746% 2.361%

7 Industrial Distribution 4.194% 2.406% -1.787%

8 Industrial

Transmission

1.160% 0.629% -0.531%

9 Electric Gen 0.222% 0.200% -0.023%

10 Total Wholesale 0.038% 0.019% -0.019%

11 Total NonCore 5.615% 3.254% -2.361%

12 Total 100.00% 100.00% 0.0% 5 Source: PG&E 2018 GCAP Workpapers Updated for Errata dated Feb.15, 2018 as shown in Excel file 6 “Gas Revenue Allocation Embedded Cost” at Tab “Output-RRQ Allocation.” ORA’s Recommendations on 7 Marginal Cost numbers are shown in ORA’s Workpapers for Marginal Cost NCO Scaled Marginal Cost Revenues as 8 adjusted. See also Attachment C from PG&E’s 2018 GCAP Workpapers Updated for Errata in Excel file “Base 9 Distribution Rev Allocation Comparison Errata 20180215” for Comparison Allocation of Gas Base Distribution 10 Revenue Requirement under Marginal Cost NCO and Rental Method, Proposed Embedded Cost, and the Current 11 (BCAP 2010 Settlement) Method. 12 13

PG&E explains in response to data request ORA-25 Q.01 subpart 3 14

below:24 15

PG&E’s MDCC estimate using NERA regression approach is 16 negative. However, in order to illustrate the impact of using 17 marginal cost based approach for revenue allocation, and its 18 comparison with embedded cost based revenue allocation, 19 PG&E used an MDCC estimate from D.05-06-029 which states 20 that the MDCC estimate is $141.75 per Dthd, in 2005 dollars. 21

22

Refer to ORA’s Workpapers for Marginal Cost NCO on Scaled Marginal Cost Revenues.



24 Response to data request ORA-25, Q.01 part 3.

10

PG&E used an appropriate escalation factor to convert this 1 estimate in 2018 dollars. PG&E used the escalated value of 2 212.47 in its work paper (for the details of the calculation, 3 please refer to the excel file labeled 4 GCAP2018_DR_ORA_Q01-part 3Atch01). However, after 5 conducting a recent review of this estimate, PG&E finds that a 6 more appropriate value is $213.90 per Dthd. 7

8 ORA Table 5–2a 9

Results of Cost Allocation: Gas Distribution Revenue Requirement 10 (in $ Thousands) 11

12

Ln No.

Description (a)

PG&E Comparison Marginal Cost 2005

Adopted in BCAP25

(b)

PG&E

Proposed26

(c)

Amount PG&E EC>MC (d=c-b)

1 Residential $1,244,090 $1,391,558 $147,468

2 Small Commercial 447,105 316,329 ($130,776)

3

Large Commercial:

Distribution

12,705

10,768

($1,937)

4 CORE NGV 5,867 4,793 $1,074)

5

Compression Cost for

GNGV2

3,899

3,914

$15

6

Total Core

1,713,666

1,727,363

$13,697

7

Industrial Distribution

54,319

42,964

($11,355)

8

Industrial Transmission

13,583

11,231

($2,352)

9 Electric Gen 3,453 3,565 $112

10 Total Wholesale 441 341 ($100)

11 Total NonCore 71,797 58,100 ($13,697)

12 Total $1,785,463 $1,785,463 $0 Source: PG&E 2018 GCAP Workpapers Updated for Errata dated February 15, 2018 as shown in Excel file “Gas Revenue Allocation – Embedded Cost Feb15 2018 (Errata)” at Tab “Output – RRQ Allocation.” PG&E Marginal Cost numbers are shown in PG&E’s Workpapers for Marginal Cost NCO Scaled Marginal Cost Revenues. See also Attachment C from PG&E 2018 GCAP Workpapers Updated for Errata in Excel file “Base Distribution Rev Allocation Comparison Errata 20180215” for Comparison Allocation of Gas Base Distribution Revenue Requirement under Marginal Cost NCO and Rental Method, Proposed Embedded Cost and Current

(BCAP 2010 Settlement) Method.

13

25

Refer to PG&E’s Workpapers for Marginal Cost NCO Scaled Marginal Cost Revenues



11

ORA Table 5–2b 1 Results of Cost Allocation: Gas Distribution Revenue Requirement 2

(in Percent) 3 4

Ln No.

Description

(a)

PG&E Marginal Comparison Cost 2005 Adopted in

BCAP27

(b)

PG&E Proposed

28

(c)

Amount PG&E EC>MC (d=c-b)

1 Residential 69.7% 77.9% 8.3%

2 Small Commercial 25.0% 17.7% -7.3%

3 Large Commercial:

Distribution

0.7%

0.6%

-0.1%

4 CORE NGV 0.3% 0.3% -0.1%

5 Compression Cost

for G-NGV2

0.2%

0.2%

0.0%

6 TOTAL CORE 95.98% 96.75% 0.8%

7 Industrial

Distribution

3.0% 2.4% -0.6%

8 Industrial

Transmission

0.8% 0.6% -0.1%

9 Electric Gen 0.2% 0.2% 0.0%

10 Total Wholesale 0.0% 0.0% 0.0%

11 Total NonCore 4.02% 3.25% -0.8%

12 Total 100.00% 100.00% 0.0% Source: PG&E 2018 GCAP Workpapers Updated for Errata dated February 16, 2018 as shown in in Excel file “Gas 5 Revenue Allocation – Embedded Cost Feb15 2018 (Errata).” PG&E Comparison Marginal Cost are shown in PG&E 6 Workpapers for Marginal Cost NCO Scaled Marginal Cost Revenues. See also Attachment C from PG&E 2018 GCAP 7 Workpapers Updated for Errata in Excel file “Base Distribution Rev Allocation Comparison Errata 20180215” for 8 Comparison Allocation of Gas Base Distribution Revenue Requirement under Marginal Cost NCO and Rental Method, 9 Proposed Embedded Cost and Current (BCAP 2010 Settlement) Method. 10

11

In D.92-12-058, the Commission adopted the Long Run Marginal Cost 12

(LRMC) methodology for the gas distribution cost allocation of California’s gas 13

utilities, namely: PG&E, SoCalGas, and SDG&E.29 To estimate the Marginal 14

Distribution Capacity Cost (MDCC) component of the LRMC, the Commission 15

adopted the NERA regression method of analysis.30 To estimate the Marginal 16

Customer Access Cost (MCAC), the Commission adopted the “Service Drop-17

27

Refer to PG&E’s Workpapers for Marginal Cost NCO on Scaled Marginal Cost Revenues.

28 PG&E 2018 GCAP Workpapers Updated for Errata dated February 15, 2018 as shown in in

Excel File “Gas Revenue Allocation – Embedded Cost Feb15 2018 (Errata)” at Tab “Output – RRQ Allocation.”

29 Ordering Paragraph #1, D.92-12-058, p. 75.

30 Conclusion of Law #3d., D.92-12-058, p. 73.

12

Regulator-Meter” (SRM) investment method originally based on the rental 1

approach.31 The Commission soon changed this to the New Customer Only 2

(NCO) method in the first update to PG&E’s LRMC in 1995.32 Unlike the gas 3

distribution function, the cost allocation applicable to PG&E’s gas transmission 4

and gas storage functions is the embedded cost methodology which was first 5

adopted pursuant to the original PG&E Gas Accord in 1997 in D.97-08-055, and 6

subsequent extensions, as approved by the Commission.33 7

The LRMC methodology applies to the utility’s basic gas transportation 8

service revenue requirement in the gas distribution service for customer costs 9

(including service lines and meters) and gas distribution capacity and operating 10

costs. The gas commodity cost is not part of the basic gas transportation 11

service, and is recovered as a separate procurement charge. 12

In addition to the base gas revenues, PG&E has additional revenue 13

requirements that are considered non-base margin. Regulatory accounts and 14

other accounts outside the base margin, but are part of the utility’s 15

transportation revenue requirements, are referred to as “non-base margin.” 16

There are different kinds of non-base margin revenues and different 17

Commission decisions apply to them. The Energy Efficiency and Low Income 18

programs, CARE and other Public Purpose Programs, expenses incurred by 19

PG&E’s Core Gas Supply to purchase gas commodity supplies and other such 20

costs are part of what is called non-base margin, and are also excluded from the 21

scope of the cost allocation methodology. These non-base margin revenue 22

requirements are funded outside of base revenues. 23

Background information regarding the LRMC and the embedded cost-24

based methodology is included in Appendix A. 25

6. Scoping Issue #13: Should the Commission adopt PG&E’s 26

proposed schedule for submission of future GCAP applications? 27

31

Conclusion of Law #5, D.92-12-058, p. 73.

32 D.95-12-053.

33 D.97-08-055, D.02-08-070, D.04-12-050, and D.07-09-045.

13

ORA does not oppose PG&E’s proposed schedule on the submission of 1

future GCAP applications. 2

III. DISCUSSION 3

A. THE COST ALLOCATION OF PG&E’S GAS 4 DISTRIBUTION 5

The Commission’s cost allocation general guidelines focus on the 6

principles of cost causation, economic efficiency, and equity as important 7

considerations in selecting an appropriate cost allocation that is both just and 8

reasonable.34 9

PG&E’s GCAP application requests to migrate to the embedded cost-10

based revenue allocation (“EC”) methodology from a marginal cost-based 11

(“MC”) revenue allocation.35 In D.92-12-058, the Commission first adopted the 12

Long Run Marginal Cost (“LRMC”) methodology for the cost allocation of gas 13

distribution utilities in California.36 Prior to the 1992 adoption of LRMC, the cost 14

allocation for gas distribution was based on embedded cost. In the 1992 15

decision, the Commission explains the conceptual framework for restructuring 16

was developed in D.86-12-009, while the implementation was developed in 17

D.87-12-038.37 18

The first principle of the conceptual approach to rate design 19 which we adopted in D.86-12-009 is that 'economic efficiency 20 dictates that rates be based on marginal cost, not embedded 21 cost We emphasized that our use of embedded costs will be 22 temporary, until the application of marginal cost principles to 23 natural gas rate design is further developed. (Id., p. 225.) 24

34

In D.92-12-058, the Commission states that one of the central principles of marginal cost pricing is cost causation and that the rates charged should reflect the change in the utility’s costs that would actually occur if there were an increase in demand. Prior to this, in D.86-12-009, the Commission states as part of guiding principles in ratemaking that “economic efficiency dictates that rates be based on marginal cost.” But, as the Commission explained in that decision, economic efficiency is not the sole consideration. The Commission states that equity considerations remain important. 35

PG&E GCAP Testimony in A.17-09-006, dated September 14, 2017, p. 3-1.

36 D.92-12-058.

37 D.92-12-058, p. 8.

14

1 The “restructuring” the Commission described in the statement below was 2

in reference to the gas restructuring of the California utilities to address the 3

fundamental changes occurring at the time in the natural gas industry. The 4

Commission stated:38 5

In 1986 the Commission identified LRMC as a cornerstone of 6 its gas restructuring agenda to address fundamental changes 7 taking place in the natural gas industry. The catalyst for change 8 was at the national level: wellhead price deregulation under the 9 Natural Gas Policy Act followed by Federal Energy Regulatory 10 Commission (FERC) Order 436 requiring interstate pipelines to 11 transport gas to customers in addition to selling their own 12 supplies. 13 14 In D.92-12-058, the Commission explains that its commitment to marginal 15

cost principles is built upon the familiarity gained from use of marginal costs in 16

developing revenue allocations and rate design for the electric utilities.39 The 17

Commission stated that although there are major differences between electric 18

and gas industries especially in the production area, there are also substantial 19

similarities between them, particularly in the areas of transmission, distribution 20

and customer services.40 21

The Commission went through a systematic formal public process to 22

develop, and ultimately adopt, the LRMC methodology. As described in D.92-23

12-058: the “LRMC methodology developed through submission of detailed 24

utility studies, formal review procedures for interested parties, and Commission-25

sponsored workshops.”41 The Commission launched an investigation in I.86-06-26

005 and a companion rulemaking in R.86-06-006 for purposes of implementing 27

38

D.92-12-058, p. 8.

39 D.92-12-058, p. 8. The Commission cites D.92749 that established the marginal cost

methodology for the electric utilities in 1981, which was approximately a decade ahead of its adoption for the natural gas industry in California.

40 D.92-12-058, p. 8.

41 D.92-12-058, p. 8.

15

a rate design for unbundling utility gas services, which culminated in the LRMC 1

decision in D.92-12-058 for the gas distribution utilities.42 2

In the succeeding cost allocation proceedings after D.92-12-058, the 3

Commission has implemented the LRMC methodology, on the basis of using the 4

NERA Regression to estimate the Marginal Distribution Capacity Cost (“MDCC”) 5

and expressed preference for the New Customer Only (“NCO”) method of 6

estimating the marginal customer access cost in the first update to the LRMC in 7

D.95-12-053.43 Following D.95-12-053, PG&E’s gas distribution cost allocation 8

has been based on the LRMC methodology. The 2005 BCAP for PG&E was 9

litigated while the last one in 2009 resulted in the adoption of a partial settlement 10

agreement.44 11

In the current GCAP, PG&E requests to migrate back to EC in Chapter 3 12

of its testimony.45 The cost allocation methodology determines how the adopted 13

gas distribution revenue requirements of PG&E will be collected from the 14

different customer classes to pay for the gas utility’s cost of service. 15

1. Description of PG&E’s Cost Allocation Proposal 16 in Testimony 17

PG&E provides a brief summary description of its testimony on 18

cost allocation in chapter 1 of its GCAP testimony stating:46 19

The current allocation to customer class (marginal cost) is no 20 longer reflective of cost-causation; customer classes are 21 overpaying or underpaying relative to their cost of service. 22 Factors contributing to this include: 23

• Growth in core customers more than offset by decline in 24

usage per customer. 25

42

D.92-12-058, the decision that adopts the LRMC methodology for gas distribution, is a result of I.86-06-005 and R.86-06-006.

43 In D.92-12-058, the Commission adopted the Rental Method for marginal customer costs. In

the first update to the LRMC after 1992, the Commission adopted the NCO method in D.95-12-053.

44 D.05-06-029 for the 2005 BCAP and D.10-06-035 for the last BCAP in 2009.

45 Id. Also, refer to Chapter 6 of PG&E GCAP testimony, p. 6-5.

46 PG&E GCAP Testimony in A.17-09-006, dated September 14, 2017, p. 1-3.

16

• Continuing reductions in use of natural gas expected in 1

accordance with California’s Assembly Bill 32 2

Greenhouse Gas emission reduction goal. 3

• Growth driver generally has shifted from capacity to 4

meet higher usage on the system, to replacement of 5

lines due to age or enhanced safety standards. 6

• Estimating demand growth from available data is 7

problematic, resulting in unreasonable distribution line 8

marginal cost estimates versus customer costs. 9

10

PG&E is requesting to migrate to the embedded cost allocation 11

methodology, which is more reflective of cost responsibility in 12

an era of declining usage and investment driven by safety and 13

capacity replacement. 14

15

This would also align with PG&E’s GT&S rate case that applies 16

the embedded cost methodology to the determination of the 17

revenue requirement by function. 18

In addition to the proposed change in the cost allocation methodology, 19

there are PG&E proposals on several other factors that impact gas rates and 20

customer bills paid by PG&E’s customers for the gas distribution cost of service. 21

The PG&E GCAP proposals include forecast gas throughput and the forecast 22

number of customers and updates to the allocation of its programs on Energy 23

Efficiency, Energy Savings Assistance, Core Brokerage Fee, Natural Gas 24

Vehicle Compression, Master Meter Discount, which all impact the gas rates 25

and customer bills paid by PG&E’s customers. Each proposal is described 26

below. 27

In Chapter 2 of PG&E’s testimony, PG&E proposes to update its on-28

system throughput and customer billing forecast.47 This PG&E proposal on the 29

throughput and customer forecast is explained and addressed in ORA Ex. ORA-30

02 by ORA witness Thomas Renaghan.48 PG&E describes the forecast it 31

proposes to use in the GCAP, in lieu of litigating throughput forecasts both in the 32

47

PG&E GCAP Testimony in A.17-09-006, dated September 14, 2017, p. 2-1.

48 Ex. ORA-02 on Throughput Forecasts by T. Renaghan.

17

2018 GCAP and in the 2019 GT&S rate case, shortly thereafter, as the 1

following:49 2

to apply the previously adopted forecasts for the year 2018 from the 3 2015 GT&S decision D.16-06-056. 4 5

In Chapter 4A, PG&E proposes to update the cost allocation for gas 6

Energy Efficiency (EE) programs and separate the Energy Savings Assistance 7

(ESA) Program allocation from the EE allocation.50 The PG&E proposal on EE 8

and ESA is explained and addressed in ORA Ex. ORA-03.51 9

In Chapter 4B, PG&E proposes to decrease the Core Brokerage Fee 10

(CBF) from $0.025 per dekatherm (“Dth”) to $0.0249 per Dth.52 In Chapter 4C, 11

PG&E proposes to increase the Natural Gas Vehicle (NGV) compression rate 12

from the current authorized rate of $0.83 per therm to $0.96 per therm.53 ORA 13

does not oppose PG&E’s proposal. 14

In Chapter 5, PG&E proposes to revise master meter discount 15

calculations provided to master meter customers on Schedule GS (Multifamily 16

Service) and Schedule GT (Mobilehome Park Service).54 The PG&E proposal 17

on master meter discounts is explained and addressed in ORA Exhibit ORA-18

04.55 19

This exhibit takes in as inputs all the recommendations of the ORA 20

witnesses that address those portions of PG&E’s proposals in the final revenue 21

allocation. These recommendations will impact the final amount of PG&E’s gas 22

rates and customer bills. 23

49

PG&E GCAP Testimony in A.17-09-006, dated September 14, 2017, pp. 6-4 through 6-5.

50 PG&E GCAP Testimony in A.17-09-006, dated September 14, 2017, p. 4A-1.

51 Ex. ORA-03 on EE and ESA by A. Cole.

52 PG&E GCAP Testimony in A.17-09-006, dated September 14, 2017, p. 4B-1.

53 PG&E GCAP Testimony in A.17-09-006, dated September 14, 2017, p. 4C-1.


55 Ex. ORA-04 on Master Meter Discounts by M. Sierra.

18

PG&E’s testimony in Chapter 6 presents the combined impact of all of 1

PG&E’s GCAP proposals on the gas rates for all PG&E gas distribution level 2

customers.56 ORA’s discovery asked PG&E to present PG&E’s GCAP 3

proposals as isolated scenarios to be able to see the impact of each proposal 4

separately. These were provided in PG&E’s Responses to ORA data request 5

ORA-03 Question 2L which are included in ORA’s Workpapers to this exhibit.57 6

PG&E proposed an update to the calculation of the CPUC Fee in this 7

GCAP in Chapter 6 of its testimony as described below:58 8

PG&E proposes an update in the calculation of the CPUC Fees that 9 PG&E’s EG customer class pays to PG&E which are passed through 10 to the CPUC. The adopted CPUC Fee applied to the EG class, is 11 based on a methodology in the 2010 Biennial Cost Allocation 12 Proceeding (BCAP) settlement (D.10-06-035) and has also been 13 adopted in Sempra’s 2009 BCAP (D.09-11-006). The adopted CPUC 14 Fee included an estimated portion of cogeneration volumes used to 15 generate electricity for on-premise usage. This chapter proposes to 16 use recorded information for the year 2016 to update the adopted 17 estimate. 18 19 All of the foregoing represent PG&E’s 2018 GCAP proposals regarding 20

cost allocation. In the next section, PG&E’s Rate Design proposals will be 21

reviewed following review of the cost allocation proposal. 22

PG&E’s embedded cost method is based on functionalization of the gas 23

distribution costs.59 The functionalization was based on PG&E’s analysis in its 24

2017 GRC. PG&E explains:60 25

PG&E has analyzed 2017 GRC Phase I Unbundled Cost 26 Category (UCC) 601 to develop the revenue requirement for “sub 27 UCCs” for distribution lines, gas service lines, and customer 28 costs. PG&E then separately analyzed the cost data to determine 29 the ongoing RCS costs since there is data available to allocate 30

56

PG&E GCAP Testimony in A.17-09-006 dated September 14, 2017, p. 6-1. See also PG&E Response to data request ORA-03, Q.2j.

57 Response to data request ORA-03, Q.2L in A.17-09-006.

58 PG&E GCAP Testimony in A.17-09-006 dated September 14, 2017, p. 6-3.

59 Refer to Table 3-1 of PG&E GCAP Testimony for the summary of gas costs by function.

60 PG&E GCAP Testimony, p. 3-1.

19

the RCS costs across customer classes. RCS costs are part of 1 customer costs in the UCC 601. The Meter and regulator costs 2 were calculated by subtracting the RCS costs from the Customer 3 costs. SRM costs were calculated by summing the service costs 4 with the customer costs less RCS costs in the UCC 601. These 5 costs are shown in Table 3-1. 6 7

PG&E makes use of various cost drivers for each function to allocate 8

functional costs to different customer classes. The total cost allocated to a class 9

is the sum of the functional costs allocated for that class.61 10

For gas distribution system costs allocation, PG&E assumes three 11

functions: (1) Service; Regulator and Meter (SRM) costs; (2) ongoing Revenue 12

Cycle Services (RCS) costs; and (3) Distribution Line costs. The function level 13

cost allocation was determined by PG&E based on cost driver data for those 14

functions. To obtain total allocated costs for each customer class, PG&E 15

calculated the sum of the function level allocations.62 16

PG&E assumes the cost driver for the SRM costs to be the meter plus the 17

module costs available for various meter sizes.63 PG&E made use of 2015 18

recorded data and calculated the number of meters by meter sizes and 19

customer class from the 2015 recorded data, and then multiplied the number of 20

“meters + module” with the corresponding purchase costs including sales tax 21

and materials burden.64 About 76 percent of residential customers were in the 22

lowest size category of the meter size shown as “<=275” CFH, another 2 23

percent were in the category size shown as “<=425” CFH, and about 2% 24

percent were in the category size shown as “<=675” CFH for residential 25

customers.65 There were a relatively insignificant number of residential 26

customers in the higher meter size categories above “<=675.” These costs by 27

61

PG&E GCAP Testimony Chap.3, p. 3-1.

62 PG&E GCAP Testimony Chap 3, p. 3-1.

63 GCAP Testimony, p. 3-2.

64 GCAP Testimony, p. 3-2.

65 PG&E GCAP Workpapers Updated for Errata in Excel file for Embedded Cost Allocation at

Tab “Input Meter Count By Size.”

20

customer class were then used to calculate the percent allocator that was used 1

to allocate the total customer cost. According to PG&E, purchase costs were 2

available for meter sizes up to 80,000 Cubic Foot per Hour (CFH). However, for 3

the sizes above 80,000 CFH, the meter plus module costs including materials 4

burden and sales tax needed to be extrapolated from the data available.66 5

PG&E used linear approximation for the sizes above 80,000 CFH.67 6

PG&E analyzed its ongoing Revenue Cycle Services (RCS) by analyzing 7

the expenses in various Federal Energy Regulatory Commission (FERC) 8

accounts for the year 2014.68 These RCS expenses were considered to be in 9

the FERC Accounts 880, 890, 893, 902, 903, 905, 908, and 910.69 Table 3-2 10

provides a high-level description of the activities for which expenses are 11

recorded in each account.70 12

PG&E proposes to implement its GCAP proposals on October 1, 2018.71 13

According to PG&E, the reason for this proposed implementation date is “to 14

begin providing the benefit of the rate design changes to residential customers 15

in time for the 2018-2019 winter season.”72 16

2. ORA’s Analysis and Recommendation 17

ORA recommends that the Commission retain the current and long-18

standing marginal cost-based revenue allocation for PG&E’s gas distribution 19

function and reject PG&E’s request to migrate to the proposed EC methodology. 20

This recommendation is based on ORA’s review and analysis indicating the 21

following issues of concern: 22

66

PG&E GCAP Testimony, p. 3-2.

67 PG&E GCAP Testimony Chap. 3, p. 3-2.


69 PG&E GCAP Testimony, pp.3-2 through 3-3.

70 PG&E GCAP Testimony, Table 3-2.



21

(1) PG&E’s testimony provides no basis to abandon the 1

principles underlying the marginal cost-based methodology nor has PG&E 2

shown evidence of the complete failure of the marginal cost methodology. 3

PG&E’s testimony does not provide evidence to show that the marginal 4

cost-based methodology for cost allocation has failed to promote economic 5

efficiency or failed to provide accurate price signals that promote energy 6

conservation and energy efficiency. The Commission’s preference for marginal 7

cost pricing for gas utilities is based on solid principles developed over the last 8

30 years, beginning in I.86-06-005/R.86-06-005. 9

For the Commission, pricing of the gas utilities’ transportation rates based 10

on LRMC was seen as a way to enhance economic efficiency stating that 11

“[k]nowledge of long-run marginal cost enables appropriate investment 12

decisions in planning capacity additions.”73 In D.86-12-009, the Commission 13

explains “[o]ur decision today is concerned with the pricing of ‘transportation’ in 14

a way that will enhance economic efficiency, meet the service needs of utility 15

customers, and at the same time provide the utilities with a fair opportunity to 16

meet their authorized rate of return.”74 In D.87-12-039 (in I.86-06-005/R.76-06-17

006), the Commission explains the underlying principles of economic efficiency 18

in rates behind its choice of marginal cost:75 19

The first principle of the conceptual approach to rate design 20 which we adopted in D.86-12-009 is that “economic efficiency 21 dictates that rates be based on marginal cost, not embedded 22 cost” We emphasized that our use of embedded costs will be 23 temporary, until the application of marginal cost principles to 24 natural gas rate design is further developed. 25 26

73

D.86-12-009, p. 5.

74 D.86-12-009, p. 10.

75 D.87-12-039, pp. 3-4.

22

In D.95-12-053, the first update of PG&E’s LRMC methodology since 1

adoption in D.92-12-058, the Commission continued to recognize the 2

importance of setting rates based on marginal costs as it explains:76 3

We recognized the importance of setting marginal cost based 4 prices when we announced our conceptual framework in D.86-5 12-009 for introducing competitive market choices into 6 California’s gas utility industry. However, we did not address 7 the complex task of adopting a LRMC methodology until 1992, 8 after we had provided each utilities’ largest customers (noncore 9 market) with competitive options for the purchase of gas, 10 encouraged market forces to decide which new interstate 11 pipeline facilities should be built, and then through the capacity 12 brokering program allowed noncore and wholesale customers 13 to directly hold firm interstate transportation capacity rights. 14 15

The 1995 decision describes the data-intensive process involved in 16

arriving at LRMC-based rates.77 The Commission provides more insight into the 17

decision behind using marginal cost in D.95-12-053:78 18

On December 16, 1992 in D.92-12-058, the Commission 19 adopted an LRMC methodology for setting prices and 20 promoting efficient capital investment decisions for California’s 21 three major natural gas utilities: PG&E, SoCalGas, and 22 SDG&E. We found that the evolution of the natural gas market 23 in California required that utility service be priced to more 24 closely reflect the way prices are set in the competitive market, 25 especially since customers served by each of the utilities had 26 substantial opportunities for bypass. We had acknowledged 27 the magnitude of the bypass threat by issuing D.92-11-052 to 28 enable PG&E and SoCalGas to use an expedited process for 29 approving discounted customer contracts that would be 30 evaluated on LRMC-based price floors We selected marginal 31 cost pricing for a utility’s forward looking costs because we 32 found it would send the most accurate price signal to 33 customers regarding how much gas to use and when to use it. 34 35

76

D.95-12-053, p. 9.

77 D.95-12-053, p. 13.

78 D.95-12-053, pp. 9-10.

23

In the succeeding years, PG&E’s cost allocation for gas distribution had 1

always been marginal cost based. The last litigated PG&E BCAP was 2

addressed in D.05-06-029, while the last BCAP adopted in 2010 before this 3

filing in A.17-09-006 was the result of a settlement. While it was a blackbox 4

settlement based on values,79 those values were derived based on marginal 5

cost-based methodologies. D.10-06-035 explains the Partial Settlement in that 6

decision:80 7

The terms of the Partial Settlement address 13 different 8 provisions. A copy of the Partial Settlement is attached to this 9 decision as Appendix 1. The first provision addresses cost 10 allocation. The Partial Settlement agrees, with one exception, 11 that the base revenue cost allocation is to be set at the mid-point 12 between the combined proposals of DRA and TURN, and PG&E’s 13 proposal. The exception is that the NGV transportation base 14 revenue allocation is to equal PG&E’s proposal. 15 16

In D.10-06-035, combined proposals of DRA and TURN were derived 17

based on marginal cost while PG&E’s proposal was based on marginal cost as 18

well.81 19

PG&E’s GCAP testimony does not provide why its gas distribution rates 20

should no longer be based on principles of economic efficiency nor explain why 21

it is requesting to migrate back to EC which provides no forward price signals.82 22

ORA asked PG&E to explain in detail how the marginal cost methodology was 23

not beneficial to ratepayers in general and/or to any specific classes of 24

ratepayers, if applicable. PG&E responded:83 25

79

Refer to Attachment C: February 16, 2018 Errata shown in PG&E’s 2018 GCAP Workpapers Updated for Errata which describes the current method as “Currently Adopted Based on Black Box Settlement With ORA/Turn in 2010 BCAP Decision.”

80 Refer to Section 3.2.1 of D.10-06-035 which describes the Partial Settlement’s

Recommendations, pp.13-10.

81 Refer to Section 3.2.2.3 of D.10-06-035 which describes Cost Allocation and Marginal Costs,

pp.13-16.

82 Embedded costs are based on historical recorded costs while marginal costs are based on

forward looking costs.

83 PG&E Response to data request ORA-04, Q.01(e).

24

PG&E does not argue that use of marginal cost revenue to 1 allocate gas base revenue has not been appropriate or, as the 2 question puts it “beneficial” to ratepayers. Particularly prior to the 3 implementation of Gas Accord I, which removed the transmission 4 and storage functions from BCAP marginal cost ratemaking and 5 instead recovered them on a function by function embedded cost 6 basis, marginal cost revenue allocation allowed the most 7 constrained gas function with the highest marginal cost for 8 incremental capacity to disproportionately dominate the allocation 9 across customer classes of gas base revenue. PG&E’s chapter 3 10 testimony states that calculation of a marginal cost revenue 11 approach is no longer stable and, looking more broadly at the 12 environment in which its gas service takes place, is unnecessarily 13 complicated and time-consuming method of allocating the two 14 remaining gas functions to which it applies, the customer function 15 and the gas distribution line function. 16

17

The above PG&E response is based on assertions. ORA attempted to 18

obtain a detailed narrative explanation and supporting documentation/evidence 19

of the alleged “failure of the marginal cost-based methodology” and PG&E’s 20

decision to migrate to the embedded cost allocation methodology, including any 21

PG&E studies undertaken. PG&E responded:84 22

PG&E has shown in its submitted work paper “4. 23 MDCC_Model.xlsm”, tab “CALC_MDCC_RESULTS” that the 24 estimate of the Marginal Distribution Capacity Cost (MDCC) is 25 negative due to the failure of the marginal cost method. This 26 failure has resulted from the declining peak day throughput which 27 can be seen in tab “INPUT_PEAK_DAY_REC_FCST”. Embedded 28 cost method implemented by PG&E does not suffer from this 29 issue since Cold Winter Day throughput proportions by customer 30 classes in the most recent average temperature year are used for 31 cost allocation, which is straight-forward. 32

33

PG&E’s testimony and responses merely point to its failure to obtain an 34

estimate of the MDCC based on the NERA regression method.85 This is 35

because PG&E obtained a negative coefficient when it used the NERA 36

84

PG&E Response to data request ORA-04, Q.01(f).

85 Refer to Table A-1 in Appendix A, PG&E GCAP Testimony in A.17-09-006, dated September

14, 2017, p. A-3.

25

regression model to estimate the MDCC value, which is not a meaningful value 1

for purposes of revenue allocation.86 2

PG&E has not presented a sufficient basis to abandon the solid principles 3

of economic efficiency and cost causation behind the marginal cost allocation 4

method in favor of the embedded cost method. PG&E’s assertions in its 5

testimony on the reasons behind the failure of the MC methodology87 should 6

instead be understood as pertaining only to the negative coefficient result 7

obtained under the NERA Regression method for the MDCC estimate in this 8

proceeding.88 The latter was the approved methodology for the gas distribution 9

MDCC in estimating the LRMC.89 10

(2) PG&E’s testimony made no mention of exploring the use of 11

any other marginal cost methods to develop an estimate of the MDCC 12

value. 13

The NERA regression method is only one of several methods to obtain 14

an estimate of the MDCC value.90 Therefore, it would be inaccurate to say that 15

PG&E’s testimony has shown that the marginal cost allocation methodology has 16

totally failed. PG&E cannot claim that all marginal cost-based allocation 17

methods have been shown to be a failure, for they have not been.91 It is only 18

86

Refer to Table A-1 in Appendix A, PG&E GCAP Testimony in A.17-09-006, dated September 14, 2017, p. A-3.

87 PG&E GCAP Testimony in A.17-09-006, p. 3-1.

88 Regression is used to calculate the relationship of the marginal investment costs to changes in

the marginal demand measure such as the Cold Winter Day for PG&E. The regression calculates the regression slope coefficient which is relationship of the marginal investment cost (i.e., the dependent variable) to changes in demand (i.e., the independent variable). The slope coefficient is multiplied against a marginal cost annualization factor to arrive at the annual marginal capacity cost of gas distribution. The latter factor represents annual marginal cost as a percent of marginal investment. A negative coefficient indicates an inverse relationship where marginal increases in demand indicates decreases in marginal investment costs or negative cost for capacity additions. Previously, one would typically expect to see a positive slope coefficient to indicate the positive cost of marginal investment for marginal increases in demand (i.e., positive costs of capacity additions).

89 D.92-12-058, Ordering Paragraph (OP) 1, p. 75.

90 Decision 92-12-058, which first adopted the Long Run Marginal Cost for California’s

respondent gas utilities, describes the other methods, pp. 32-34.

91 PG&E GCAP Testimony in A.17-09-006, dated September 14, 2017, p. A-7, explains that as a

(continued on next page)

26

the NERA Regression methodology that did not provide a positive estimate of 1

the MDCC value. PG&E’s testimony and workpapers show that PG&E obtained 2

a negative coefficient for the estimate of the MDCC value based on the NERA 3

regression.92 But PG&E’s testimony was silent regarding the use of another 4

marginal cost method to develop an estimate of the MDCC.93 5

In D.92-12-058, the Commission decision approved adoption of the Long 6

Run Marginal Cost (LRMC) method for the respondent gas utilities in California, 7

namely PG&E, SoCalGas, and SDG&E.94 Although the NERA regression 8

method was ultimately the approved method for purposes of estimating gas 9

distribution capacity marginal costs, there were several other marginal cost 10

methods considered by the Commission in the same decision.95 The approval 11

and adoption of the NERA Regression Method for purposes of LRMC revenue 12

allocation does not necessarily preclude the utility from exploring the use of 13

other approaches. The Commission has shown in the past that other marginal 14

cost methods for purposes of marginal cost estimation could be considered, 15

such as the Discounted Total Investment Method (DTIM).96 PG&E’s GCAP 16

testimony does not include exploration of these other marginal cost 17

methodologies to obtain an estimate of the MDCC. 18

(continued from previous page) result of the negative coefficient based on the NERA regression, “it is necessary for PG&E to explore alternative means for developing revenue allocation factors for distribution capacity costs other than MDCC. To that end, PG&E is proposing an embedded cost approach for revenue allocation.”

92 Refer to Table A-1 in Appendix A, PG&E GCAP Testimony in A.17-09-006, dated September

14, 2017, p. A-3.

93 Appendix A, PG&E GCAP Testimony in A.17-09-006, dated September 14, 2017 (Revised for

Errata dated Feb 15, 2018), p. A-5.

94 Findings of Fact #1 and 27, Conclusion of Law #3, and Ordering Paragraph #1, D.92-12-058

in I.86-06-005 and R.86-06-006 dated December 16, 1992, pp. 64-75.

95 Decision 92-12-058, which first adopted the Long Run Marginal Cost for California’s gas

utilities, pp. 32-34.

96 Decision 95-12-053, at page 37, where the Commission indicates willingness to consider

incorporating other approaches to estimate the marginal cost of capital investments. In that decision, the Commission directed PG&E to provide a scenario that incorporates the use of the DTIM for the estimate of the marginal cost of capital investments.

27

(3) PG&E is aware of other marginal cost methods to estimate an 1

MDCC value, but was silent regarding any effort to use them in its GCAP 2

testimony. 3

PG&E made no mention of any effort to use another marginal cost 4

method in its GCAP testimony.97 In its 2017 GRC proceeding (A.16-06-013), 5

PG&E presented other marginal cost methods to estimate an MDCC value.98 6

PG&E’s testimony in the 2017 GRC Phase II presented at least four (4) methods 7

to estimate an MDCC value, but PG&E’s testimony in this GCAP fails to mention 8

even one of those other marginal cost methods.99 The noticeable absence of 9

any analysis in PG&E’s GCAP testimony of other marginal cost methodology 10

options explored, in addition to the NERA Regression for the estimation of the 11

MDCC, is particularly noteworthy.100 PG&E omitted any mention of another 12

marginal cost method to develop a reasonable estimate of the MDCC after 13

PG&E obtained a negative coefficient based on the NERA Regression 14

method.101 15

(4) PG&E admits to lack of readily available reliable data to 16

explore alternative marginal cost-based methods such as the DTIM. 17

ORA had several meetings with PG&E. One of the reasons for the 18

meetings was to question PG&E regarding the DTIM after ORA did not obtain 19

responsive answers to data request ORA-04 Q1(f). In that meeting, ORA 20

97

Refer to Chapter 3 and Appendix A, PG&E GCAP Testimony in A.17-09-006, dated September 14, 2017.

98 In A.16-06-013, which was the 2017 PG&E GRC Phase II (Exhibit PG&E-9).

99 ORA is aware that PG&E’s witness on the MDCC in this proceeding is the same witness

PG&E had for its MDCC on the electric side, specifically in A.16-06-013, which was the 2017 PG&E GRC Phase II (Exhibit PG&E-9). In that electric proceeding, the PG&E witness made use of the approach called DTIM to obtain an estimate of an MDCC value. The method is called Discounted Total Investment Method (DTIM).

99 In that electric proceeding, the PG&E witness

also presented other alternative approaches such as the Present Worth Method (PWM) 99

and the Total Investment Method (TIM), aside from the NERA Regression method.

99

100 Refer to data request ORA-04, Q.1(f) and PG&E’s Response to the same. ORA had to follow

up after PG&E’s Response failed, twice, to be responsive to the specific question regarding other options explored.

101 The NERA Regression method was the approved methodology for gas distribution long run

marginal cost estimates based on D.92-12-058.

28

learned that PG&E did not have readily available, reliable data to pursue a DTIM 1

analysis at the time of PG&E’s preparations to file this GCAP last year.102 2

Therefore, PG&E was limited to using the NERA Regression method in its 3

marginal cost analysis. The inability of PG&E to use another marginal cost-4

based method to estimate the MDCC value should not be interpreted as a 5

failure of the other potential methodologies.103 6

In meetings, PG&E stated it did not have the available reliable data 7

needed to pursue the DTIM method to estimate the MDCC at the time of the 8

PG&E GCAP filing. However, PG&E can perform a DTIM analysis at the system 9

level.104 In particular, when PG&E filed its GCAP application on September 14, 10

2017, it did not have a forecast of gas distribution capacity growth to perform a 11

system-level DTIM calculation for the gas MDCC.105 12

Due to the lack of reliable data for the DTIM calculation, PG&E only 13

showed the NERA Regression Methodology to estimate the MDCC under a 14

marginal cost-based method.106 As a result, as explained on pages A-6 through 15

A-7 in Appendix A of PG&E’s testimony, including the calculation of a negative 16

coefficient of the MDCC through NERA Regression, PG&E states “it is 17

necessary for PG&E to explore alternative means for developing revenue 18

102

Based on a March 19, 2018, meeting between ORA and PG&E as memorialized in PG&E’s response to ORA-03 Mtg 03192018 Answer A2.

103 Response to data request ORA-22 Q.2 explains the absence of reliable data for purposes of

the DTIM method. It was PG&E’s first mention of another option to develop an MDCC estimate. In an in-person meeting between ORA and PG&E, PG&E discloses for the first time that it had no available reliable data to conduct a DTIM analysis at the time of its GCAP filing in 2017.

104 Response to ORA-03 Mtg 03192018 Answer A1 where PG&E states that PG&E today can

perform a DTIM calculation for gas MDCC at only a system level. PG&E states that the DTIM calculation could not be performed at any level of geographic differentiation.

105 Based on March 19, 2018 meeting between ORA and PG&E as memorialized in PG&E’s

response to ORA-03 Mtg 03192018 Answer A2.

106 Response to data request ORA-22, Q.2 explains the absence of reliable data for purposes of

the DTIM method. It was PG&E’s first mention of exploring another option to develop an MDCC estimate. In an in-person meeting between ORA and PG&E, PG&E discloses for the first time that it had no available, reliable data to conduct a DTIM analysis at the time it was preparing for its GCAP filing in 2017.

29

allocation factors for distribution capacity costs other than MDCC. To that end, 1

PG&E proposes an embedded cost approach for revenue allocation.”107 2

(5) PG&E’s calculation results in a system-level DTIM-based 3

analysis for the MDCC estimate that was a positive value, and not a 4

negative value, as shown in response to ORA Data Request No. 29 5

Question 1. 6

Following the March 19, 2018, meeting with PG&E, ORA asked PG&E in 7

data request ORA-29 to prepare a DTIM-based analysis to estimate the MDCC 8

value.108 In objections to the ORA data request, PG&E continued to cite lack of 9

readily available data to perform a DTIM-based analysis on a geographically 10

differentiated basis.109 However, PG&E was able to calculate and provide an 11

MDCC value based on a DTIM analysis on a system-level basis which ORA now 12

recommends for PG&E’s MDCC marginal cost allocation.110 PG&E stated these 13

objections in response to ORA’s data request:111 14

QUESTION 1 15 As discussed during the meeting on March 19, 2018 between ORA 16 and PG&E on the preparation of estimates of Marginal Distribution 17 Capacity Costs based on the Discounted Total Investment Method 18 (DTIM), please provide a geographically differentiated gas DTIM 19 analysis for purposes of the 2018 PG&E GCAP similar to the 20 electric DTIM analysis that PG&E prepared and presented in A.16-21 06-013. (Please refer to Table 6-1, reproduced below from PG&E 22 2017 General Rate Case Phase II in A.16-06-013, Updated and 23 Amended Prepared Testimony Exhibit No. PG&E-9, Volume 1 on 24 Marginal Costs, dated December 2, 2016 at Chapter 6 Marginal 25 Distribution Capacity Costs, sponsored by PG&E witness Mr. 26 Thomas L. Troup.) 27

107

Appendix A, PG&E GCAP Testimony in A.17-09-006 dated September 14, 2017 (Revised for Errata dated Feb 15, 2018), p. A-7.

108 Response to data request ORA-29, Q.01.

109 Following its March 19 in-person meeting with PG&E, data request ORA 29 requested PG&E

perform a DTIM analysis for its GCAP to estimate an MDCC value.



30

ANSWER 1 1 PG&E objects to this data request for a DTIM analysis on a 2 geographically differentiated basis on the following grounds: 3 1. PG&E does not have readily available geographically 4 differentiated gas load forecasts that would be necessary to 5 perform the requested geographically differentiated gas DTIM 6 analysis requested by ORA. PG&E’s preliminary determination 7 about what might be possible to develop geographically 8 differentiated gas load indicates that obtaining geographical load, 9 weather station data and economic drivers could cause a strain on 10 resources and processing powers for each respective model that 11 may not have a significant impact on PG&E’s system level 12 throughput. 13 14 2. PG&E also objects because even assuming that the 15 geographically differentiated gas load forecasts were available, 16 gas MDCC data is too different from the electric MDCC data to be 17 usable in the electric MDCC model. The electric MDCC model 18 includes a voltage-level differentiation between primary and 19 secondary distribution for which there is no analogous 20 differentiation for the gas distribution system. In addition, the gas 21 MDCC calculation methodology, as adopted in D.05-06-029, uses 22 capital additions data for MWC 29, 47, and 50. While PG&E has 23 an electric MWC that is analogous to the gas MWC 29 (capital 24 additions generally for new connections, including new capacity, 25 i.e., line extensions for those new connections) and two MWCs 26 that together are largely analogous to MWC 47 (capital additions 27 generally for adding capacity to the existing distribution system), 28 the electric MDCC model does not include an electric MW 29 analogous to gas MWC 50 in which is recorded capital 30 investments for gas distribution general reliability. 31 32 (6) ORA recommends that the Commission find the Discounted 33

Total Investment Method (DTIM) to be the most appropriate method to 34

obtain an estimate of the MDCC on a marginal cost-based method given the 35

characteristics of PG&E’s capital investments and load. 36

As mentioned, the DTIM was one of the marginal cost-based methods 37

considered in D.92-12-058 as the Commission describes the four methods in 38

D.92-12-058: 112 39

112

D.92-12-058, p. 33.

31

We have four methods of estimating the marginal cost of capital 1 investments for consideration: present worth (PW); total 2 investment; The National Economic Research Associates, Inc. 3 (NERA) regression; and discounted total investment. By briefing, 4 parties reached consensus on the total investment method, 5 except for PG&E and the City of Vernon (Vernon) who prefer PW 6 and SDG&E who advocates the NERA regression method and, as 7 an alternative, the discounted total investment method. In more 8 detail, the four methodologies are: 9 10 1. The Total Investment methodology computes an arithmetic 11 average by dividing the total investment during the planning 12 horizon by the total load growth during the same period. The 13 resulting unit marginal cost is then annualized using a Real 14 Economic Carrying Cost (RECC) factor. The RECC capital 15 amortization formula levelizes a stream of future payments in a 16 manner similar to an annuity calculation but with an inflation 17 adjustment. RECC models incorporate assumptions for service 18 life, salvage value, cost of capital, inflation rates, and discount 19 rates. 20 21 2. The NERA Regression methodology uses a model developed 22 by NERA to obtain a marginal unit capital cost by regressing the 23 cumulative changes in investment with cumulative changes in 24 load. Parties used a combination of historical and forecast period 25 data. The marginal unit cost is then annualized using the RECC 26 factor discussed above. 27 28 3. Present Worth methodology computes the difference between 29 the present value of a planning period's stream of system 30 investments, assuming project spending commences in the 31 current year, and the present value of the same stream of 32 investments, assuming project spending is delayed one year. 33 The difference between the two present value streams is 34 annualized by dividing by the average annual change in the 35 demand measure used for the planning horizon. 36 37 4. The Discounted Total Investment method computes a marginal 38 unit cost by dividing the present value of the planning period's 39 investments by the total load growth. A present value is used in 40 the numerator to give additions further into the future less weight 41 than investments in earlier time periods. The marginal unit cost is 42 then annualized using an RECC factor. 43 44

32

PG&E’s previous testimony in the 2017 GRC Phase II describes the 1

appropriateness of the DTIM in cases of lumpy investments, the incorporation of 2

capacity load value, and the time value of money.113 In the 2017 GRC 3

testimony, PG&E states:114 4

The DTIM proposed here for MTCC (and MDCC) corrects for 5 the defect in the TIM of not including time value of money; the 6 DTIM is simply the discounted version of the TIM that takes into 7 account the time value of money. While both the DTIM and the 8 PWM incorporate the time value of money to account for the 9 timing and size of investments—a key methodology attribute 10 when costs are lumpy—PG&E proposes using the DTIM, 11 because it incorporates the time value for the capital additions 12 and capacity load, and thus this method alone recognizes that 13 load capacity also has value. 14 15 In this GCAP, PG&E’s testimony states that its actual and forecasted 16

capacity-related investments address local pockets of constrained gas 17

distribution system capacity and this leads to inconsistent capacity growth from 18

year to year on a system-wide basis.115 According to PG&E, capital investments 19

that occur occasionally and with large variations year to year could be described 20

as “lumpy” in nature.116 In addition, PG&E describes the nature of its recorded 21

and forecast distribution peak CWD throughput growth as variable in nature, 22

without a consistent trend.117 Given PG&E’s description of the nature of its 23

capacity-related investments and its variable throughput growth, and PG&E’s 24

description of the DTIM method, which was proposed by PG&E in the 2017 25

GRC proceeding, ORA finds sufficient indications on the appropriateness of the 26

113

PG&E Testimony in 2017 GRC Phase II (Exhibit PG&E-9), p. 6-10 states: “Of the four incremental methodologies for estimating T&D marginal costs discussed in D.92-12-058 - RM, TIM DTIM, and PWM, only the PWM and DTIM are sensitive to the timing of lumpy investments.” RM refers to Regression Method, TIM refers to the Total Investment Method, DTIM refers to Discounted Total Investment Method, and PWM refers to Present Worth Method.

114 PG&E 2017 GRC Testimony in A.16-06-013, p. 1-16.

115 Appendix A, PG&E GCAP Testimony in A.17-09-006 dated September 14, 2017 (Revised for


116 PG&E 2017 GRC Testimony in A.16-06-013, p. 1-16.

117 Appendix A, PG&E GCAP Testimony in A.17-09-006 dated September 14, 2017 (Revised for


33

DTIM in this case among the four marginal cost methodologies considered in 1

D.92-12-058. 2

Given the negative coefficient obtained based on the NERA Regression 3

for the calculation of the MDCC value, DTIM seems to be the most appropriate 4

choice on marginal cost-based methods to address inconsistent capacity growth 5

from year to year that lead to lumpy investments and incorporates the time value 6

of capacity load.118 In PG&E’s 2017 GRC A.16-06-013, PG&E proposed the 7

DTIM to calculate the MDCC of PG&E’s distribution electric system which was 8

“lumpy” in nature. In its 2017 GRC Phase II testimony, PG&E proposed the 9

Commission find the DTIM method reasonable to estimate MDCC values for 10

purposes of its marginal distribution capacity costs, which according to PG&E, 11

was a significant change to prior adopted methodology.119 According to PG&E’s 12

GRC testimony, the DTIM methodology incorporates the time value of money 13

while calculating the average investment cost for a stream of lumpy capacity 14

investments.120 This is similar to PG&E’s gas distribution investments that 15

PG&E describes as having large year to year variation.121 16

(7) Illogical results and negative coefficient results with the 17

NERA Regression are entirely possible given long running Energy 18

Efficiency and conservation policies in the state. 19

For the NERA Regression results, PG&E states that “the regression 20

coefficient for the negative MDCC are statistically valid at the 95 percent 21

confidence level, which implies the statistical relationship is now not only 22

negative, but robust, which is in conflict with the fact that costs for capacity 23

118

Appendix A, PG&E GCAP Testimony in A.17-09-006 dated September 14, 2017, p. A-6.

119 PG&E 2017 GRC Ph. II Testimony dated December 2, 2016, pp. 6-3 through 6-8.

120 PG&E 2017 GRC Ph. II Testimony, p. 6-3.

121 PG&E’s actual and forecasted capacity-related investments are to address local pockets of

constrained gas distribution system capacity. This leads to inconsistent year-to-year capacity growth on a system-wide basis. Further, weather adjusted recorded and forecasted distribution peak CWD throughput growth is variable and, as Table A-3 below shows, does not result in a consistent trend.

34

additions have a positive investment cost.”122 The regression result obtained by 1

PG&E with the negative MDCC thus appears to be an entirely nonsensical 2

result. However, such illogical outcomes from the regression method are 3

possible as explained by ORA in the 1990s, before the Commission adopted 4

LRMC in D.92-12-058. Excerpts from ORA’s testimony in I.86-06-005/R.86-06-5

006 relevant to the construction of load data to avoid negative marginal cost 6

results is reproduced below.123 7

The point is that obtaining a negative coefficient and illogical marginal 8

cost results could be possible outcomes from the NERA regression given the 9

impact of ongoing Energy Efficiency and Conservation programs on gas 10

consumption and demand. PG&E has previously shown that there are methods 11

to address the issue without abandoning the marginal cost-based methodology, 12

as described in the following excerpts from ORA’s Testimony in April 1992. 13

Excerpts from ORA’s Testimony in I.86-06-005/R.86-06-006, p. 6-14, 14

dated April 1992, by ORA124 Witness Chris Danforth, Construction of Load 15

Data to Avoid Negative Marginal Costs 16

17 38. Energy conservation efforts by customers has had a 18 greater impact on gas usage than electric usage largely 19 because retrofit and behavioral modifications are easier to 20 achieve on gas side. Apparently for this reason, gas usage has 21 fallen in some of the years captured in the marginal cost 22 analysis for some of the utilities, especially PG&E. Because of 23 this situation, if one uses actual load data adjusted to reflect the 24 required weather conditions in a NERA-style regression, the 25 resulting marginal cost will be negative depending on the years 26 chosen. The results also can be potentially unstable depending 27 the years chosen for the analysis. 28 29 39. PG&E has overcome this problem by using a measure of 30 load that is based on positive changes in the numbers of 31

122

Appendix A, PG&E GCAP Testimony in A.17-09-006 dated September 14, 2017 (Revised for Errata dated Feb.15, 2018), p. A-7.

123 Excerpts from ORA Report on Natural Gas Long-Run Marginal Costs I.86-06-005 dated April

1992, p. 6-14.

124 At the time, ORA was referred to as the Division of Ratepayer Advocates (DRA).

35

customers multiplied by use per customer on the type of design 1 day PG&E wants to reflect in its analysis. The changes in the 2 number of customers are set to zero in years in which the 3 customer base decreases, and the use per customer, though 4 varying from year to year and generally falling, is always a positive 5 number. Therefore the load additions will always be positive, 6 assuring positive marginal costs. 7 8 40. DRA agrees with PG&E's approach for distribution costs 9 recommends it be applied to the other utilities even though load 10 decreases for them are not enough to cause negative marginal 11 costs. PG&E's approach more closely reflects the loads 12 actually used to plan distribution additions, even though, as 13 discussed above, hourly loads at a very local non-coincident 14 level are used in planning. To not use this approach will 15 capture energy conservation from existing customers which 16 probably does not significantly affect the addition of new 17 equipment at the distribution level. 18 19

8) The NERA Regression method applies only to the MDCC 20

calculation, and not to the Marginal Customer Access Cost (MCAC), and 21

therefore, the marginal cost method to estimate the MCAC function 22

remains valid for use in this proceeding. 23

The coefficient for the MDCC estimate for the distribution function is 24

independently determined from the marginal cost estimate for the customer 25

function. This means that even though a negative coefficient was obtained for 26

the MDCC estimate, the marginal cost method for the customer function 27

determined through PG&E’s estimate of the Marginal Customer Access Cost 28

(MCAC), remains usable. The NERA Regression method applies only to the 29

MDCC, and not to the MCAC determination. Therefore, the marginal cost 30

method to estimate the MCAC function remains viable for use in this 31

proceeding. The MCAC methodology remains valid and PG&E’s GCAP 32

testimony in fact proposes to continue the two previously adopted components 33

of MCAC, namely the marginal connection equipment costs (known as the 34

SRM) and marginal ongoing RCS costs.125 35

125

Appendix A, PG&E GCAP Testimony, p. A-8.

36

9) ORA’s review shows that the PG&E MCAC estimates produce 1

lower scaled marginal customer revenues compared to those under the EC 2

for the customer function at the gas distribution level.126 3

PG&E’s MCAC analysis shown in PG&E’s Workpapers is based on 4

PG&E’s numbers and assumptions on marginal customer costs, including 5

throughput and customer gas billing numbers. ORA’s review of PG&E’s 6

workpapers shows that the scaled marginal customer costs are lower compared 7

to those obtained under the EC method, particularly for the Residential customer 8

class.127 Translated into a monthly customer cost, PG&E’s MC analysis showed 9

a scaled marginal customer cost that was approximately $11 a month per 10

residential customer based on the NCO method.128 On the other hand, PG&E’s 11

EC method shows a total monthly average customer cost for individually 12

metered residential customers of $16.14 a month.129 The same PG&E 13

Workpaper provided in a discovery response shows a slightly higher amount of 14

$17.79 a month per residential is obtained based on the Rental Method.130 15

These monthly residential customer costs were presented in support of PG&E’s 16

request in the rate design proposal to increase PG&E’s minimum monthly 17

transportation charge from the existing $3 a month to $15 a month for non-18

CARE Residential customers, which is a 500 percent increase. The cost 19

allocation methodology plays a significant part in PG&E’s proposal to increase 20

the minimum transportation charge. As explained in Section III.B.4, ORA 21

disagrees with the PG&E proposal on the amount of the minimum bill increase. 22

126

PG&E 2018 GCAP Workpapers Updated for Errata Feb 15 2018 Excel File “Base Distribution Rev Allocation Comparison Errata 20180215.” See also PG&E Response to ORA-03, Mtg 3192018 Atch01.

127 PG&E’s 2018 GCAP Workpapers Updated for Errata Feb 15 2018 Excel File “Base

Distribution Rev Allocation Comparison Errata 20180215.” See also PG&E Response to ORA-03, Mtg 3192018 Atch01.

128 PG&E Response to ORA in ORA-03, Mtg 3192018 Atch02.

129 See PG&E RD Model for 2018 GCAP provided in Updated PG&E Workpapers for Errata

dated 2/15/2018 at Tab Res-MinTranspChargeLevel.

130 PG&E Response to ORA in ORA-03, Mtg 3192018 Atch02.

37

10) ORA’s review shows that the EC methodology results in 1

higher costs allocated to core customers when compared to one based on 2

either PG&E’s estimate of the scaled MC-based values or ORA’s 3

recommendation using the DTIM-based MDCC estimate and the MCAC 4

NCO as adjusted in the final allocation. 5

For purposes of cost allocation comparison, PG&E’s testimony presents a 6

marginal cost estimated value for the MDCC even though PG&E explains that 7

the MC analysis results in a negative MDCC estimate.131 According to PG&E, it 8

made use of the MDCC value adopted in the PG&E 2005 decision in D.05-06-9

029 and escalated that 2005 value to a 2018 price level.132 This explains why 10

PG&E still had a positive MDCC value in its cost allocation/rate model.133 11

Based on the use of this PG&E proxy MDCC value, ORA’s review of PG&E’s 12

resulting revenue allocation, keeping all PG&E GCAP proposals unchanged 13

except the EC is changed to MC, results in lower costs allocated to Core, 14

particularly to Residential customers.134 To view the comparison of the resulting 15

revenue allocation, please refer to PG&E Attachment C (Attached to this 16

Exhibit). ORA’s recommendation on marginal cost using a DTIM-based 17

calculation for the MDCC and the MCAC NCO as adjusted in the final allocation 18

is also shown in Attachment C to this Exhibit. 19

PG&E’s GCAP testimony provides an insight into the magnitude of the 20

impact of PG&E’s EC proposal versus present rates as PG&E states:135 21

The net impact of PG&E’s proposed throughput forecast and 22 allocation method updates compared to revenues at present rates 23 using PG&E’s proposed throughput forecast is an increase to 24 core classes of approximately $75 million (transportation and 25 public purpose program surcharge revenues) and an increase to 26

131

PG&E Response to data request ORA-29, Q1 Atch 01CONF.

132 Appendix A at p. A-5.

133 PG&E explains in response to data request ORA-25, Q1 subpart 3 that it made use of the

2005 BCAP adopted annual marginal capacity cost and escalated that 2005 value to the year 2018.

134 Refer to Table 3-4, PG&E Testimony dated September 14, 2017, p. 3-7.

135 PG&E GCAP Testimony dated September 14, 2017, p. 1-5.

38

noncore classes of approximately $10 million (transportation and 1 public purpose program surcharge revenues) during the first year 2 of the GCAP, assuming currently adopted revenue requirements 3 at the time of the application. 4 5 The impact of ORA’s recommendation versus PG&E’s proposal on cost 6

allocation is shown in ORA Table 5-1a at the beginning of this exhibit at column 7

d. For residential customers, PG&E’s EC proposal will allocate approximately 8

$52 million more in revenue responsibility compared to ORA’s recommendation 9

to use marginal cost based on the DTIM calculation with the same amount of 10

costs allocated to small commercial customers, but slightly lower allocations to 11

large commercial, and NGV1 customers than ORA’s recommendation. With 12

respect to G-NGV2 customers, both ORA and PG&E methods would allocate 13

the same share of costs. 14

11) The LRMC methodology is more appropriate for cost 15

allocation in terms of promoting economic efficiency and providing price 16

signals to customers especially given the anticipated implementation of 17

GHG emission costs.136 18

As previously discussed, economic efficiency goals and the provision of 19

more accurate price signals are the reasons behind the Commission’s historical 20

preference for the LRMC methodology since the methodology was first adopted 21

for the electric utilities in 1981 and then for gas utilities in 1992.137 According to 22

PG&E, an expected decision on recovery of greenhouse gas emission 23

allowance costs and its annual gas true up could affect the numbers in this 24

proceeding.138 Since the LRMC methodology is more appropriate for cost 25

allocation in terms of promoting economic efficiency and providing more 26

136

CPUC decisions in D.86-12-009, D.87-12-038, D.92-12-058, and D.95-12-053 reference goals of achieving economic efficiency and providing price signals.

137 See for instance D.92749 (i.e., where the Ordering Paragraph adopts the methodology for

calculating marginal cost for electric utilities in Appendix B) and D.96-04-050 (COL#1) which states that marginal cost principles should be the starting point and central focus of revenue allocation and rate design for setting Edison’s rates. In D.92-12-058, the Commission first adopted MC methodology for gas utilities.

138 PG&E GCAP Testimony dated September 14, 2017, p. 1-2.

39

accurate price signals to customers, the anticipated decision on cost recovery of 1

GHG emission allowance costs makes it imperative for the Commission to retain 2

a cost allocation methodology that is anchored on cost causation and calculated 3

based on forward-looking costs.139 D.95-12-053, in particular, points out “that 4

the evolution of the natural gas market in California required that utility service 5

be priced to more closely reflect the way prices are set in the competitive 6

market.”140 D.95-12-053 explains that the Commission had also acknowledged 7

the magnitude of the bypass threat by issuing D.92-11-052 “to enable PG&E 8

and SoCalGas to use an expedited process for approving discounted customer 9

contracts that would be evaluated on LRMC-based price floors.”141 The 10

Commission explains in D.95-12-053 that “[w]e selected marginal cost pricing 11

for a utility’s forward looking costs because we found it would send the most 12

accurate price signal to customers regarding how much gas to use and when to 13

use it.”142 14

The need for accurate price signals is important with respect to the 15

implementation of the GHG emission allowance costs recovery, as PG&E points 16

out:143 17

PG&E has not yet been authorized to include the GHG price 18 signal in gas rates. Once that price signal is included in rates in 19 2018 (CPUC decision is pending), the price signal will increase in 20 intensity as the amount of free allowances provided by the Air 21 Resources Board (ARB) are reduced, the market price for 22 allowances increase, and the value of free allowances California 23 gas utilities can use to directly offset the purchase cost of GHG 24 emission allowances declines per the ARB. 25

139

For instance, see D.92749, D.86-12-009, D.87-12-038, D.92-12-057, D.92-12-058, D.95-12-053, D.96-04-050, and others.

140 D.95-12-053, pp. 9-10.

141 Id.

142 Id.

143 PG&E Response to data request ORA-04, Q.01(d).

40

12) The EC methodology could result in higher bill volatility for 1

residential customers.144 2

The PG&E 2018 GCAP Tool was provided by the Applicant in response 3

to the Commission’s request made during the first Prehearing Conference in this 4

proceeding.145 The Commission expects that the Tool will be of assistance to 5

the Commission in terms of taking actions to comply with SB 711.146 PG&E first 6

provided the GCAP Tool to ORA on January 30, 2018 and after discussions 7

between ORA and PG&E regarding the Tool’s functionality, this Tool was 8

subsequently replaced with an improved version on March 27, 2018 called the 9

PG&E 2018 GCAP Enhanced Tool (Enhanced Tool).147 PG&E clarified that the 10

Tool did not incorporate the impact of the Winter hedge program because the 11

GCAP deals with the transportation rate design while the hedging of commodity 12

prices are implemented in monthly pricing guided by PG&E’s Core Procurement 13

Incentive Mechanism (CPIM).148 14

ORA’s run of the PG&E GCAP Enhanced Tool indicates that applying the 15

MC methodology while keeping all other PG&E GCAP proposals unchanged, 16

results in less bill volatility compared to PG&E’s proposed EC methodology. 17

144

The 2018 PG&E GCAP Enhanced Tool in A.17-09-006 is Proprietary/Trade Secret per Declaration of Patti Landry, March 26, 2018.

145 Scoping Memo and Ruling of Assigned Commissioner and Administrative Law Judges in

A.17-09-006, p. 4.

146 Id. SB 711 was approved by the California Governor on October 3, 2017. This bill would

require the Public Utilities Commission to make efforts to minimize bill volatility for residential customers, and explicitly authorizes the Commission to do this by modifying the length of the baseline seasons or defining additional baseline seasons. See the website link for SB 711 at https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill_id=201720180SB711

147 Refer to emails from PG&E regarding the delivery of the GCAP Tool and GCAP Enhanced

Tool in CD format to ORA on January 30, 2018 and March 27, 2018. The “Enhanced Tool” features are described in the Tool Documentation Enhanced features. Among others, the Enhanced Tool allows user specified Gas Base Distribution Revenue Requirement Allocation Method. In short, as the user, ORA is able to specify its own Gas Base Distribution Revenue Allocation Method for use in the tool. Refer to p. 12 of the Tool Documentation.

148 PG&E Response to data request ORA-20, Q.5 a & b.

41

This reduction in bill volatility was a result based on a difference in the cost 1

allocation method alone.149 2

The results of the Enhanced Tool scenario runs performed by ORA is 3

discussed at length in the Rate Design Proposals in section III.B. There are five 4

(5) scenario settings options relevant to the cost allocation policy choice in the 5

Enhanced Tool. ORA initially planned to recommend “Scenario 6” for the 6

allocation of the Gas Base Distribution Revenue Requirement of the Enhanced 7

Tool as a user-specified setting. However, ORA understands from PG&E’s 8

clarification that the Enhanced Tool does not have the capability of retaining rate 9

changes assuming various throughput forecasts.150 For this reason, ORA 10

changed its recommendation to “Scenario 10” which uses the “live link” in the 11

tab “ResDistributionRateScenario” of the Enhanced Tool based on PG&E’s 12

guidance in the response to clarify how Scenario Settings Tab of the Tool based 13

on ORA’s user-specified setting in the ResDistributionRateScenario.151 14

Scenarios “6” and “10” in the Scenario Settings Control Panel of the 15

Enhanced Tool is shown in Attachment D of this testimony. This user specified 16

setting is included in the Enhanced Tool in tab “ResDistributionRateScenario” 17

based on the data inputs shown as outputs of ORA’s recommendation in the 18

Rate Design (RD) Model.152 This links the results of the two models. 19

ORA’s run of the Enhanced Tool to show a difference in the allocation 20

method for the Gas Base Distribution Revenue Requirement shows a difference 21

from PG&E Scenario “1” to either ORA’s Scenario “6” or “10.” As clarified, ORA 22

recommends Scenario “10” which fully incorporates both ORA’s marginal cost 23

recommendation and throughput forecast while Scenario “6” in the Tool still 24

makes use of PG&E’s Updated Throughput. The residential customer bill 25

results of ORA’s recommendation can be viewed in the tab “TotalProposedBills” 26

149

Refer to ORA’s Workpapers on the Enhanced GCAP Tool.

150 PG&E Response to data request ORA-33, Q.4 & 5.

151 PG&E Response to data request ORA-33, Q.4 & 5.

152 Tool Documentation for the PG&E GCAP Enhanced Tool in A.17-09-006, p. 12.

42

of the Enhanced Tool.153 The change in the proposed bills from the present can 1

be viewed in the tab “ChangeInBills_FromPresent” of the Enhanced Tool.154 2

The amount of change in bills reflects a difference in both cost allocation method 3

as well as throughput forecast. 4

13) PG&E’s request to migrate to the EC method should be 5

denied. 6

As explained in the foregoing, the LRMC methodology is not just about 7

obtaining a negative coefficient for the MDCC estimate based on the NERA 8

Regression.155 PG&E’s request to migrate to the EC methodology primarily 9

relates to the fact that PG&E’s LRMC analysis based on the NERA regression 10

model produced a negative coefficient estimate for the Marginal Distribution 11

Capacity Cost (MDCC). According to PG&E, this is one reason PG&E has 12

proposed an embedded cost approach.156 PG&E explains that the negative 13

coefficient for the MDCC value is unreasonable and cannot be used in this 14

proceeding.157 As explained in the foregoing, PG&E could have used another 15

marginal cost approach for the MDCC, but did not. 16

PG&E provides an explanation of the negative result of the regression 17

methodology stating:158 18

To understand the resulting negative MDCC estimate, it is 19 important to review the methodology and input data. The 20 regression method attempts to derive statistically the 21 relationship between the capacity investment cost and capacity 22 growth. For distribution capacity for natural gas, the 23 methodology has used changes in annual peak CWD 24 throughput as proxy for changes in capacity. Historically this 25 proxy proved reliable, as there was strong correlation between 26 capacity growth and throughput growth. 27

153

Tool Documentation for the PG&E GCAP Enhanced Tool in A.17-09-006, p. 13.

154 Tool Documentation for the PG&E GCAP Enhanced Tool in A.17-09-006, p. 13.

155 NERA stands for National Economic Research Associates Inc. as that acronym is spelled out

in D.92-12-058, p. 32.

156 Appendix A, PG&E’s GCAP Testimony in A.17-09-006, p. A-6.

157 Id.

158 Appendix A, PG&E’s GCAP Testimony in A.17-09-006, p. A-6

43

1 PG&E asserts that the proxy it relied on for distribution capacity changes 2

(i.e., the changes in annual peak Cold Winter Day (CWD)159) is no longer 3

reliable.160 4

In a data response, PG&E states:161 5

A3. PG&E believes that using the net change in average annual 6 billed core customer accounts and core class peak CWD 7 throughput as a measure of capacity growth is no longer a 8 reasonable proxy for the capacity growth driving investments in 9 gas distribution capacity. 10 11 As to why PG&E no longer believes that net changes in core 12 customers and associated peak CWD throughputs no longer 13 provide a reasonable proxy for capacity growth, PG&E believes 14 it is helpful to understand what capital additions are considered 15 as marginal for calculating MDCC. 16 17

PG&E was mainly attempting to explain why the NERA Regression 18

method was failing to give PG&E a usable outcome for the MDCC. It does not 19

provide a reasoned basis for abandoning LRMC and migrating to EC. ORA 20

discusses each of the reasons cited by PG&E on why the marginal cost method 21

it used failed. 22

PG&E provides explanations of the changes in the relationships of the 23

three Major Work Categories (MWC) for MWC 29, 47, and 50 used for purposes 24

of capacity-related capital additions in the estimate of the MDCC.162 PG&E 25

further explains that MWC 50, which has a lower value for purposes of marginal 26

capacity additions, has now become an increasingly larger share relative to the 27

two other MWCs, in the calculation of the MDCC.163 The surge in MWC 50 28

relative to MWC 29 and 47 is not entirely unexpected given the renewed focus 29

159

Appendix A, PG&E’s GCAP Testimony in A.17-09-006, p. A-5.


161 PG&E Response to ORA-03, Mtg 3192018 Q01.A3.



44

on gas pipeline safety and reliability following a series of gas pipeline failures, 1

such as the PG&E San Bruno pipeline explosion in September 9, 2010, and the 2

Rancho Cordova incident on Christmas Eve of 2008. 3

PG&E has pointed out in testimony the current trends of declining load 4

with increasing costs.164 PG&E attributes the growth in distribution revenue 5

requirements primarily due to safety and lifecycle replacement.165 According to 6

PG&E, safety refers to “reducing gas distribution equipment and pipeline failures 7

and accidents” while lifecycle replacements refer to “replacing the gas 8

distribution equipment and pipelines that are beyond their depreciable life and 9

require replacement.”166 PG&E clarified that it takes a risk-based approach to 10

determine lifecycle replacements.167 11

Capacity investments on safety and reliability and those for replacement 12

of worn equipment do not count for purposes of load-growth related marginal 13

capital additions, but they are necessary investments of capital costs imposed 14

on the existing system by the need to maintain safety and reliability and prevent 15

a decline in the operating capacity to serve existing levels of output or demand. 16

While the utility should be prepared to augment its capacity to accommodate 17

additional incremental load, throughput, or demand, the utility is also expected 18

to be prepared to maintain its operating capability to provide safe and reliable 19

service.168 To maintain the state of readiness of its operating capability, the 20

utility is expected to provide for replacement costs wherever deemed necessary 21

in recognition of the wear and tear on its system. Utilities, such as PG&E, know 22

that this is a normal part of maintaining the expected operating capability to 23

serve. If replacement costs, or safety and reliability costs, become an 24

increasing share of the utilities’ capacity costs relative to the size of load-growth-25

164

PG&E GCAP Testimony, pp. 3-5 through 3-6.

165 PG&E Response to data request ORA-3 Q.2(c).

166 PG&E Response to data request ORA-2 Q.1(e).

167 PG&E Response to data request ORA-13, Q.1 part_a part h.

168 See for instance Public Utilities Code secs. 959(b), 961(b).

45

related investments, it simply means that the utility is spending more to prevent 1

a decline in operating capacity to serve existing load while maintaining safety 2

and reliability. As ORA explains below, PG&E has been spending to prevent a 3

negative change in output, but these replacement costs were already built into 4

their LRMC calculations. 5

Although a separate replacement cost adder is no longer allowed in the 6

calculation of LRMC,169 the provision for replacement costs is already built-into 7

the LRMC calculation via the real economic carrying charge (RECC). The 8

Commission explains this in D.05-06-029:170 9

Economic literature apparently does not explicitly address the 10 issue of replacement costs as an element of long run marginal 11 costs. However, the record before us demonstrates that PG&E 12 does include the cost of replacing existing facilities in its marginal 13 distribution costs through the real economic carrying charge, 14 which recognizes the costs of new facilities and the costs of 15 replacing them in the future. Thus, including the replacement cost 16 in marginal distribution costs double counts these costs. 17 Moreover, although the economic literature may not explicitly 18 address this point, including replacement costs as an element of 19 marginal costs is conceptually inconsistent with economic theory. 20 Once a utility makes an investment in new facilities to serve 21 increasing customer demand, the utility will repair or replace 22 those facilities without regard for incremental increases in 23 demand. For these reasons, we eliminate the replacement cost 24 adder from the equation used to calculate marginal customer 25 costs. (Emphasis added) 26

27 In D.05-06-029, the Commission explains the underlying reasons why 28

replacement cost adders were previously separately included in LRMC 29

calculations:171 30

The Commission required PG&E to include those costs in its long 31 run marginal cost calculation finding that doing so “is consistent 32 with marginal cost economic theory” (D.95-12-053, mimeo., at 22) 33 and that “in the long run, all costs are variable and there is an 34

169

Conclusion of Law #6, D.05-06-029, p. 26.

170 Discussion in D.05-06-029, p. 20 and Findings of Fact #14 and 15, D.05-06-029, p. 25.

171 D.05-06-029, p. 19.

46

opportunity cost to not replacing the existing system.” (D.97-04-1 082, mimeo., pp 47-48.) 2

3 ORA found a reference regarding the inclusion of replacement costs via 4

the RECC in a NERA Discussion Paper showing mathematically how 5

replacement costs are already built into the RECC.172 The PG&E LRMC 6

calculations use the RECC.173 7

Based on the foregoing, ORA would disagree that the increasing share of 8

replacement and safety costs in the utilities’ gas distribution capacity costs 9

relative to the size of load-growth-related investments should be a reason to 10

argue against the LRMC allocation methodology. 11

PG&E’s testimony cites to a number of other factors to explain why it 12

believes the historically strong correlation between capacity growth and 13

throughput growth has broken down.174 These factors are intended to explain 14

why PG&E obtained a negative coefficient in the calculation of the MDCC to 15

calculate a marginal distribution capacity cost rather than reasons that support a 16

PG&E cost allocation migration to embedded costs. These factors relate to: (a) 17

energy efficiency; 175 (b) PG&E’s actual and forecasted capacity-related 18

investments are to address local pockets of constrained gas distribution system 19

capacity, leading to inconsistent capacity growth from year to year on a system-20

wide basis;176 (c) extreme cold weather events do not necessarily affect PG&E’s 21

gas distribution system on a system-wide basis given the large size and varying 22

172

Excerpt of “Attachment C” specific to the RECC from a much longer paper that discusses marginal costs more broadly. The paper Attachment C is excerpted from is “A Framework for Marginal Cost-Based Time-Differentiated Pricing in the United States: Topic 1.3” dated February 21, 1977, and was prepared by National Economic Research Associates, Inc. (now known as NERA Economic Consulting).

173 Table A-2 in Appendix A, PG&E 2018 GCAP Testimony, p. A-4.


175 Appendix A, PG&E GCAP Testimony in A.17-09-006 dated September 14, 2017, p. A-6.

176 Appendix A, PG&E GCAP Testimony in A.17-09-006 dated September 14, 2017 at p. A-6.

When inconsistent capacity growth happens, large capital investments occur occasionally as needed, and these are considered to be “lumpy.” Refer to PG&E’s Response to data request ORA_019 Q.2(d) in the 2019 GT&S in A.17-11-009 for the use of the word “lumpy.”

47

climates in PG&E’s service territory, and instead, such events affect only 1

portions of PG&E’s system on any single day;177 and (d) the regression 2

coefficients for the negative MDCC are statistically valid at the 95 percent 3

confidence interval, implying a statistically robust relationship, but are in conflict 4

with the fact that costs for capacity additions on a localized basis correlate 5

positively, meaning that localized capacity addition has a positive investment 6

cost.178 7

PG&E provided data showing a decline in average gas consumption for 8

PG&E residential customers over a 12-year period from 2004-2016.179 PG&E 9

also provided supplemental data on residential gas usage over the period 1995 10

through 2017 on a monthly basis.180 Plotting the data on a chart shows a 11

general declining trend. But as previously explained, the MDCC calculation is 12

not based on average gas consumption, but on peak usage. Planning of the 13

PG&E gas distribution system is based on peak day marginal demand 14

measures for PG&E’s system design criteria and cost causation.181 PG&E plans 15

the capacity of its system based on the highest demand, even if residential 16

average gas consumption is declining. 17

This is evident in how PG&E describes how it plans for the loads it is 18

obligated to serve:182 19

20 PG&E analyzes load demand based on computerized hydraulic 21 models. Distribution loads by model name and cities by model 22 name are summarized in the attachment 23 “5b_Gas_APD_Loads_by_Model.xlsx.” In addition, please find a 24 general description of how design loads are determined below. 25 PG&E has an obligation to provide continuous, uninterrupted 26 service to all core customers, even under the design day known 27

177

Appendix A, PG&E GCAP Testimony in A.17-09-006 dated September 14, 2017, p. A-7.

178 Appendix A, PG&E GCAP Testimony in A.17-09-006 dated September 14, 2017, p. A-7.

179 PG&E Response to data request ORA-09, Q.03(f).

180 PG&E Response to data request ORA-09, Q.3(f) Supplemental 01.

181 Finding of Fact #25, D.92-12-058, p. 66.

182 PG&E Response to data request ORA-018 Q.5b.

48

as Abnormal Peak Day (APD). The APD design temperature is 1 defined as the coldest temperature that may be exceeded one 2 in every 90 years, on average. 3 Gas systems must also provide continuous, uninterrupted 4 service to all customers, core and noncore, under the design 5 day known as Cold Winter Day (CWD). The CWD design 6 temperature is defined as the coldest temperature that may be 7 exceeded one in every two years, on average. 8 For most distribution systems, APD is the peak capacity driver, 9 because the core load under those conditions is the highest 10 system load probable. The Abnormal Peak Day (APD) demand 11 in thousands of cubic feet per hour (mcfh) by hydraulic model is 12 summarized in the attachment 13 “5b_Gas_APD_Loads_by_Model.xlsx.” 14 15 In contrast to the declining average usage, PG&E describes the nature of 16

its recorded and forecast distribution peak CWD throughput growth as variable 17

in nature, without a consistent trend.183 As described by PG&E in testimony, 18

both recorded and forecast peak CWD were not showing a consistent trend, 19

neither of consistent declines or increases. This is contrary to the statement in 20

PG&E’s data response:184 21

PG&E anticipates that the throughput data used in estimating the 22 Marginal Distribution Capacity Cost (MDCC) using the Regression 23 Methodology most likely will continue to show a declining trend, 24 while the incremental investment used in the regression method 25 will maintain the positive trend. Therefore, the marginal cost 26 method may not be reliable for distribution revenue allocation or 27 other cost-based assessments. 28 29 Regarding the first factor PG&E cites, it is the policy of the State of 30

California to promote energy efficiency and conservation, and has been the 31

state’s policy for some time now, with billions in ratepayer funding in support of 32

this policy.185 The California Energy Commission, together with the Commission 33

and publicly-owned utilities are on a path for doubling energy efficiency savings 34

183

Appendix A, PG&E 2018 GCAP Testimony in A.17-09-006 dated September 14, 2017 (Revised for Errata dated Feb 15, 2018), p. A-6.

184 PG&E Response to data request ORA-13, Q.3.

185 Final 2017 Integrated Energy Policy Report dated February 2018, p. 5.

49

by 2030.186 The expected long term effect of a sustained energy efficiency and 1

conservation policy187 is to reduce overall gas consumption levels, and even 2

with increasing PG&E customer numbers,188 reduced gas consumption per gas 3

customer as greater energy efficiency and conservation is achieved is 4

possible.189 5

PG&E is appropriately incentivized to pursue energy efficiency and 6

conservation190 since the Commission has authorized revenue decoupling for 7

PG&E, where the amount of revenues PG&E collects are no longer a function of 8

the amount of gas sales PG&E makes.191 The observed trend of declining 9

average gas use in recent years apparently has not impacted PG&E’s revenues 10

as indicated by PG&E’s returns on its investments, which remain at healthy 11

levels.192 12

While the average use of gas may be declining, it does not necessarily 13

mean that there is reduced need for additions to PG&E’s distribution capacity 14

nor is it indicative of other emerging trends in gas usage and capacity. One 15

class of Core customers, Core NGV, has enjoyed high growth in demand (i.e., 16

7.27% average annual growth rate from 2006-2016), but PG&E says the 17

throughput volumes from the Core NGV are too small to outweigh the decline in 18

other distribution-level customer classes.193 19

The state’s pursuit of both Energy Efficiency and reduced Greenhouse 20

Gas (GHG) Emissions is occurring at the same time as the pursuit of an 21

aggressive renewable energy policy, with the goal of achieving 50% 22

186

Final 2017 Integrated Energy Policy Report dated February 2018, p. 5.


188 PG&E Response to data request ORA-30 Q.01.

189 PG&E Response to data request ORA-09 Q.3(f) Supplemental01.

190 PG&E obtained approximately $21.915 million in Energy Efficiency performance incentive

awards for the period 2015-2016 G/5136-E; SCE 3655-E; SDG&E 3109-E/2606-G; SoCalGas 5182; and PG&E 3880-G-A/5136-E-A.

191 PG&E Response to data request ORA-09 Q.03(c).


193 PG&E Response to data request ORA-13, Q1(l).

50

Renewables by the year 2030.194 As a result, there is a certain amount of 1

change occurring in the electric grid. There could be an increase in gas usage 2

in response to the intermittency of renewable energy sources and the so-called 3

duck curve, where there is a need to ramp up gas generation for load following 4

and the need for gas capacity to address sudden hourly surges in demand when 5

the sun stops shining or the wind stops blowing, and shows possibility for steep 6

ramping needs at times of peak capacity.195 Therefore, even though average 7

residential gas use may be declining, and overall gas consumption may decline 8

as a result of California’s policies, the need for PG&E to stand ready with 9

capacity to serve the highest level of demand on its gas system has not been 10

shown to have diminished. 11

Moreover, increases in energy efficiency and renewable energy do not 12

spell the end for gas usage. The use of Renewable gas is also being 13

encouraged by California’s state policy.196 Renewable gas is being explored as 14

a tool to reduce methane emissions.197 On March 30, 2018, PG&E filed Advice 15

Letter 3961-G to support the pursuit of a Voluntary Renewable Natural Gas 16

Procurement Pilot.198 17

PG&E states that “some areas experience more gas load growth than 18

others mainly as a result of new customers or existing customers adding 19

demand.”199 PG&E identified some “counties which recently experienced 20

moderate growth on PG&E’s system,” including, “Alameda, Contra Costa, 21

Fresno, Sacramento, San Francisco, San Joaquin, and Santa Clara.”200 This 22

seems to indicate load growth occurring in a geographically dispersed manner 23

194

Senate Bill 350.

195 Refer to CAISO Fast Facts on “What the Duck Curve Tells Us About Managing a Green

Grid,” available at www.caiso.com.


197 Final 2017 Integrated Energy Policy Report dated February 2018, pp. 10-11.

198 PG&E Advice Letter 3961-G dated March 30, 2018, p. 1.

199 PG&E Response data request ORA-018, Q.5(c) subpart b.

200 PG&E Response data request ORA-018, Q.5(c) subpart c.

51

and is one reason ORA contemplated looking into PG&E’s geographically 1

differentiated load growth.201 2

The second factor PG&E cites for why it believes the historically strong 3

correlation between capacity growth and throughput growth has broken down 4

actually highlights two important considerations: 1) that there are local pockets 5

of constraints on PG&E’s gas distribution system that its capacity investments 6

are meant to address, and 2) that those lead to capacity investments that are 7

inconsistent from year to year on a system-wide basis. Capacity investments 8

that exhibit this inconsistent nature are referred to as “lumpy.” The lumpiness 9

factor indicates that the Discounted Total Investment Method (DTIM) may be 10

more appropriate for PG&E at this time. DTIM is described as a more 11

appropriate marginal cost methodology for capacity investments that exhibit 12

lumpiness.202 13

The last two factors PG&E cites to only point to more reasons to look at 14

PG&E’s gas distribution system based on a geographically differentiated basis 15

for load and investments rather than from a total system-level perspective as the 16

NERA regression method would.203 This indicates that a DTIM-based analysis 17

on a geographically differentiated basis may be a more appropriate approach to 18

PG&E’s long run marginal cost analysis.204 However, as PG&E indicates in a 19

data response, it had no readily available data for a geographically-differentiated 20

DTIM analysis.205 21

PG&E cites to customer classes overpaying or underpaying relative to 22

their cost of service and attributes this to the current allocation methodology 23

(marginal cost) being no longer reflective of cost-causation when it states:206 24

201

ORA Data Request data request ORA-29, Q.1.

202 PG&E 2017 GRC Testimony dated December 2, 2016 in A.16-06-013, p. 1-15.

203 PG&E 2017 GRC Testimony. dated December 2, 2016 in A.16-06-013, p. 1-10.

204 PG&E 2017 GRC Testimony dated December 2, 2016 in A.16-06-013, p. 1-16.


206 PG&E GCAP Testimony in A.17-09-006 dated September 14, 2017, p. 1-3.

52

The current allocation to customer class (marginal cost) is no 1 longer reflective of cost-causation; customer classes are 2 overpaying or underpaying relative to their cost of service. 3 4

While on the one hand PG&E attributes the occurrence of customers 5

overpaying or underpaying on the marginal cost allocation methodology and 6

asserts marginal cost is no longer reflective of cost-causation, on the other hand 7

in a discovery response, PG&E attributes the structural shortfall (i.e., customer 8

overpayments and underpayments) to the dated throughput forecast adopted in 9

the 2010 BCAP stating:207 10

The throughput forecast adopted in 2010 for GCAP ratemaking 11 results in a 5% shortfall of adopted core transportation 12 revenues allocated and designed using that forecast. That 13 structural shortfall amounts to $90 to $100 million even if the 14 temperatures over the course of the year were perfectly 15 normal. If temperatures are warmer than normal, the structural 16 shortfall only adds to the absolute undercollection that is then 17 put into rates on January 1 with the Annual Gas True-Up in the 18 middle of winter. Additionally, the shortfall is not static but 19 growing over time as the throughput forecast adopted in 2010 20 becomes more and more out of date and the impacts of energy 21 efficiency, climate change, and soon, response to the GHG 22 price signal, cause usage per residential customer to decrease. 23 Updating the throughput forecast used to calculate GCAP-24 determined rates would eliminate the structural part of the 25 shortfall of undercollections. And PG&E’s proposal to update 26 the throughput forecast used on a regular and efficient 27 ratemaking basis via the forecast adopted in its GT&S rate 28 cases would make sure the forecast used for GCAP 29 ratemaking does not grow stale again. 30 31

ORA notes that the above statements from PG&E point to the fact that 32

“updating the throughput forecast used to calculate GCAP-determined rates 33

would eliminate part of the shortfall of undercollections.” It is therefore 34

inaccurate to singularly attribute to the marginal cost methodology the 35

occurrence of over-and under collections and pinpoint marginal cost as being no 36

longer reflective of cost causation. Marginal cost makes use of a throughput 37 207

PG&E Response to data request ORA-20, Q.3(f).

53

forecast in its calculation, and if that throughput forecast is stale, then the 1

marginal cost methodology itself should not be blamed. The structural shortfall, 2

in reference to customers overpaying or underpaying, is a throughput issue, not 3

a marginal cost methodology issue. In this GCAP, PG&E’s proposed throughput 4

forecast is from the 2015 GT&S adopted decision.208 5

PG&E found some errors in its workpapers described below. PG&E 6

found errors in the recorded data used for the capital additions for purposes of 7

the marginal cost MDCC analysis, as acknowledged by PG&E in a data 8

response, and which were corrected by PG&E following discovery.209 9

ORA also found discrepancies in the throughput data between those in 10

PG&E’s workpapers and those in its MDCC model.210 In Table A-3 of its GCAP 11

testimony, PG&E presents 2005-2019 weather-adjusted recorded and forecast 12

distribution cold winter day throughput growth (in MDth/CWD).211 In a 13

clarification of the discrepancies noted by ORA between data in the MDM 14

Workpapers and in the MDCC Model on the recorded and forecast throughput, 15

PG&E explains the reasons for the discrepancies:212 16

A5. The variance can be primarily attributed to outdated data 17 that was used in the MDCC model. The MDM report reflects 18 the updated percentage factors and would explain the variance 19 between columns O versus Y from ORA’s handout. 20

3. ORA Recommendation on Other PG&E Requests 21 for Updates to Allocation 22

As described earlier in this exhibit, PG&E proposed changes in this 23

GCAP presented in Chapter 6 of its testimony, as shown below:213 24

208

PG&E 2018 GCAP Testimony in A.17-09-006, p. 2-1.



211 Appendix A, PG&E GCAP Testimony, p. A-7. The information as presented by PG&E was

verified to contain inaccuracies as ORA could not reconcile the numbers shown in the PG&E Workpapers and in the MDCC Model.


213 PG&E GCAP Testimony in A.17-09-006 dated September 14, 2017 (Revised for Errata), p. 6-

3.

54

PG&E proposes an update in the calculation of the CPUC Fees that 1 PG&E’s EG customer class pays to PG&E which are passed through 2 to the CPUC. The adopted CPUC Fee applied to the EG class, is 3 based on a methodology in the 2010 Biennial Cost Allocation 4 Proceeding (BCAP) settlement (D.10-06-035) and has also been 5 adopted in Sempra’s 2009 BCAP (D.09-11-006). The adopted CPUC 6 Fee included an estimated portion of cogeneration volumes used to 7 generate electricity for on-premise usage. This chapter proposes to 8 use recorded information for the year 2016 to update the adopted 9 estimate. 10 11

ORA does not oppose PG&E’s proposed update. PG&E clarified whether the 12

allocation of the gas base distribution revenue requirement would impact the 13

update to CPUC fees:214 14

PG&E’s request to update the CPUC fees applicable to the EG 15 customer class would not be impacted by the adopted decision on 16 the allocation of the gas base distribution revenue requirement. 17 PG&E’s proposal to update the proportion of the cogeneration gas 18 throughput that is used to generate electricity used onsite is 19 independent of all revenue allocations in the GCAP. 20 21

ORA’s review indicates the Commission adopted in Decision D.10-06-035 a 22

reduced payment of the CPUC Fee.215 This decision originally approved and 23

adopted the methodology for calculation of the current CPUC fees applicable to 24

the EG class of PG&E.216 25

When asked whether PG&E’s request to update CPUC fees applicable to 26

the EG customer class would not be impacted by the adopted decision on the 27

allocation of the gas base distribution revenue requirement, PG&E responded 28

that its proposal to update the proportion of the cogeneration gas throughput 29

that is used to generate electricity used onsite is independent of all revenue 30

allocations in the GCAP.217 To verify, PG&E provided the workpapers in an 31

214

PG&E Response to data request ORA-5, Q.1(c).

215 PG&E Response to data request ORA-5 Q1(b) cites to D.10-06-35, Conclusion of Law #1,

the partial settlement in the BCAP, which included as its 9th provision, the reduced CPUC fee, p.

9.

216 PG&E Response to data request ORA-5, Q.1(b).

217 PG&E Response to data request ORA-5, Q.1(c).

55

Excel file entitled “2016_EG_CPUC_Fee_Factor_Study.xlsx” for how the 42% 1

was derived. 2

ORA asked PG&E to clarify the request on CPUC Fees. PG&E 3

explained:218 4

PG&E’s request for an update in the calculation of the CPUC 5 Fees applicable to the EG customer class is a request to 6 update an input to the calculation, namely the proportion of the 7 cogeneration gas throughput that is used to generate 8 electricity used onsite. This proportion is then multiplied to the 9 cogeneration volumes to give the amount of therms that 10 determine how much of the total CPUC fee is applicable to the 11 EG customer class. This amount of therms is then, as a 12 percentage of the total amount of therms applicable to the 13 CPUC fee, multiplied by the PG&E’s total CPUC revenue 14 amount to come up with the amount of the CPUC fee that the 15 EG class are accountable for. 16 17 ORA’s review indicates that the current calculation was approved in the 18

BCAP decision as well as the requirement for an update to the calculation to be 19

done in the next cost allocation case, which is now this GCAP. PG&E 20

explained:219 21

The calculation of the CPUC fees applicable to PG&E’s EG 22 customer class was decided in a the 2010 BCAP settlement, 23 which also adopted the 15% meant to represent the proportion 24 of the cogeneration gas throughput that is used to generate 25 electricity used onsite based on estimates calculated during the 26 case litigation period. D.10-06-035 (p.9) also adopted in full the 27 Partial Settlement in the BCAP that required PG&E to update 28 this value in its next gas cost allocation proceeding. 29 30 ORA asked PG&E to provide the basis for the request to do their update 31

with the use of 2016 recorded information.220 PG&E’s response to ORA 32

confirmed that the GCAP testimony reference to using only 2016 is in error and 33

218

PG&E Response to data request ORA-5, Q1(e).

219 PG&E Response to data request ORA-5, Q1(f).

220 PG&E GCAP Testimony in A.17-09-006 dated September 14, 2017 (Revised for Errata), p. 6-

3.

56

clarified that instead, PG&E made use of 2014, 2015, and 2016 recorded 1

information for the update.221 2

ORA verified that based on recorded information for the years 2014 3

through 2016, the calculation from the PG&E workpapers provided an estimated 4

percentage of cogeneration volumes used to generate electricity for on-premise 5

usage results in a 42 percent update to the previous 15 percent.222 The 42 6

percent update represents the average percentage for the three years 2014 7

through 2016. 8

Based on the recorded information reviewed by ORA, ORA does not 9

oppose PG&E’s proposed update. 10

According to PG&E, an update to 42 percent of cogeneration gas 11

throughput used to generate onsite electricity would result in a CPUC Fee paid 12

by the EG class of $0.00016 per therm in comparison to the previous $0.00006 13

based on the adopted 15 percent in the BCAP settlement. PG&E confirmed that 14

the proposed change from 15 percent to 42 percent results in additional CPUC 15

Fees to the EG class in the amount $0.00010 per therm,223 which also includes 16

the Franchise Fees and Uncollectibles Fees.224 17

According to PG&E, the PG&E tariffs related to the CPUC Fees 18

applicable to the EG customer class can be found in PG&E’s Preliminary 19

Statement Part B for the G-EG and G-EGBB tariffs.225 In the same response, 20

PG&E also provided their website link with the EG tariff components shown on 21

sheet 15.226 22

221

PG&E Response to data request ORA-5, Q.1(g).

222 EG CPUC Fee Factor Study for years 2014, 2015, and 2016.

223 $0.00016 per them minus $0.00006 per therm = $0.00010 per therm.

224 PG&E Response to data request ORA-5, Q.2(k).

225 PG&E Response to data request ORA-5, Q.1(j).

226 Id. https://www.pge.com/tariffs/assets/pdf/tariffbook/GAS_PRELIM_B.pdf

57

B. PG&E RATE DESIGN PROPOSALS 1

1. Description of PG&E’s Rate Design Proposals 2 in the GCAP Application 3

According to PG&E, the Applicant’s rate design proposals are designed 4

to address excessive bill volatility and high peak winter bills.227 5

1) PG&E proposes to create a 3-month Peak Winter baseline season, which 6

means redefining the Winter baseline season to 7

December/January/February, to replace the current 5-month winter 8

baseline season which includes November and March, and to have a 9

Nine-Month (Summer) Non-Peak Season including the two months of 10

November and March;228 11

2) PG&E proposes to Phase-in the return of a residential bundled tiered rate 12

ratio with a goal of 1.2 to 1;229 13

3) PG&E proposes to reduce volumetric gas transportation rates by 14

increasing the non-CARE residential minimum monthly transportation 15

charge to $15 while continuing to exempt PG&E’s CARE residential 16

customers from the minimum monthly transportation charge;230 17

4) PG&E proposes to further reduce volumetric transportation rates by 18

creating a second tier non-CARE minimum monthly transportation charge 19

of $45 for the top percentage of individually-metered residential 20

customers who have very high maximum daily peak gas therm 21

consumption of at least 15 therms a day.231 22

As explained by PG&E, the goal of the proposed rate design changes is 23

to moderate excessive bill volatility for the residential class. PG&E stated:232 24

227

PG&E GCAP Testimony in A.17-09-006 (Revised for Errata), p. 1-5.

228 PG&E GCAP Testimony in A.17-09-006 (Revised for Errata), pp. 7-2 through 7-3.




232 PG&E GCAP Testimony in A.17-09-006 (Revised for Errata), p. 7-1.

58

This chapter presents Pacific Gas and Electric Company’s 1 (PG&E) proposed residential rate design changes to moderate 2 excessive bill volatility. PG&E does not propose any rate 3 design changes to classes other than residential. 4 5

PG&E then provides a set of proposed rate solutions that include 6

changes in the baseline season structure, the ratio of the tiered rates (tier ratio), 7

and non-California Alternate Rates for Energy (CARE) individually metered 8

minimum monthly transportation charges, as well as a proposal to create a 9

second tier of non-CARE minimum monthly transportation charges that would 10

only apply to the top few percent of non-CARE individually metered customers 11

with daily peak demands that require metering commensurate with larger 12

customers, such as small commercial.233 PG&E’s testimony provides first-year 13

bill impacts for the proposed changes on a composite basis including the impact 14

of the cost allocation changes proposed in previous chapters.234 15

PG&E expects that the reduction in volatility will be most prominent for 16

customers with higher winter usage and those with moderate usage who “either 17

exceed baseline allowances during colder than normal weather or typically use 18

only a modest amount in excess of the baseline allowances during normal 19

temperatures.”235 20

PG&E further explains the proposal to increase the Non-CARE residential 21

customer minimum gas transportation rates:236 22

PG&E proposal is to increase the minimum monthly 23 transportation charge for non-CARE individually metered 24 customers from $3 to $15. This means that if a customer would 25 pay less than the minimum monthly transportation charge based 26 on its volumetric usage, then the difference between the 27 minimum monthly transportation charge and their current bill will 28 be added to their bill so that their bill is at least the amount of 29 the minimum monthly transportation charge, please see the 30 figure below for the formula. 31

233

PG&E GCAP Testimony in A.17-09-006 (Revised for Errata), p. 7-2.



236 PG&E Response to data request ORA-08, Q.5a.

59

1 Minimum Monthly Trans. Charge - Non-CARE Trans. Charge = Difference 2 (D) 3 If D > 0, then: 4 Non-CARE Trans. Charge + D = Final Non-CARE Trans. Charge 5 6 PG&E also proposes what is effectively a second tier for the 7

minimum monthly non-CARE residential transportation charge 8

where customers with very high peak usage during the course 9

of a year would pay a minimum monthly transportation charge of 10

$45 with the same calculation formula as described above. 11

12

Under PG&E’s proposal the non-CARE residential monthly transportation 13

charge based on volumetric usage cannot be less than $15 a month and for 14

those with usage of at least 15 therms per day, the minimum monthly 15

transportation charge will be $45 a month. 16

2. ORA Recommendation on Baseline Season 17

SB 711, approved in October of 2017, gives the Commission explicit 18

authority to modify the length of the baseline seasons or define additional 19

baseline seasons.237 Pursuant to SB 711, the Commission is required to make 20

efforts to minimize bill volatility for residential customers.238 ORA’s 21

recommendation is within the authority provided to the Commission by SB 711. 22

ORA recommends adopting a 3-month peak winter season consistent with 23

PG&E’s proposal, but to reject PG&E’s proposal to include the two months of 24

March and November currently included in PG&E’s Winter season as part of the 25

summer season. 239 ORA recommends that, in addition to the adoption of a new 26

3-month peak winter baseline consisting of the months of 27

December/January/February, a 2-month Off-Peak winter period, consisting of 28

the months March and November. 29

237

See the website link for SB 711 at https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill_id=201720180SB711

238 Id.


60

SB 711 requires the Commission to make efforts to minimize bill volatility 1

specifically for residential customers. ORA asked PG&E what it meant by “bill 2

volatility.”240 PG&E defines bill volatility below:241 3

Bill volatility generally can be defined as the fluctuations of the 4 gas and/or electric bill for a customer in a relatively short amount 5 of time such as month to month and season to season. Deeming 6 bill volatility as excessive depends on the situations and what 7 factors are driving the bill volatility. PG&E’s Residential rate 8 design with volumetric rates (only $3 non-CARE minimum 9 monthly transportation charge is revenue collected as a customer 10 charge) naturally lead to significant volatility in bills as they are 11 driven by throughput, which is primarily driven by changes in 12 temperatures. Therefore, it would be more precise to define 13 excessive bill volatility as a situation when a customer’s bill 14 changes disproportionately in relationship with their usage over a 15 month to month or season to season period and without a 16 reasonably strong relationship to changes in cost of service. 17 18

ORA asked whether PG&E monitors “bill volatility,” and if so, to describe 19

whether this monitoring occurs at the gas distribution end-use on a daily basis, 20

and if not, then to indicate the customer level and frequency at which PG&E’s 21

monitoring occurs.242 PG&E explains:243 22

PG&E monitors bill volatility both in terms of the effective rate 23 structure and also its average change in bills when 24 implementing monthly pricing. However, PG&E’s ability to 25 manage bill volatility due to changes in the commodity cost 26 component of monthly pricing rates is extremely limited at best. 27 The transportation rate design is practically the only tool 28 available to PG&E for reducing monthly bill volatility; the 29 residential customer may always choose the option of the 30 Balanced Payment plan if he or she wants it. 31

32

ORA inquired about PG&E’s data metric to monitor and measure “bill 33

volatility” that is in use by PG&E to detect its presence at the gas distribution 34

240

ORA-08 Q1(a) data request.

241 PG&E Response to data request ORA-08, Q.1(a).

242 ORA-08, Q1(b) data request.

243 PG&E Response to data request ORA-08, Q.1(b).

61

end-user level for the residential customer.244 The response indicates no 1

specific data metric on bill volatility, but one could observe differences in 2

customer bills at a moment in time. PG&E explains:245 3

As stated in response to Question B, PG&E monitors bill 4 volatility in terms of effective rate structure and when 5 implementing monthly pricing. It is difficult to set a metric for the 6 effective rate structure, but one way PG&E monitors the bill 7 volatility is through evaluating what the current and proposed 8 customer bill would be at a moment in time. The goal of sound 9 rate design is to allocate the cost of service and any 10 incremental costs to all customers for a balanced allocation. 11 Monthly pricing allows PG&E to monitor gas distribution end-12 use rates on a monthly basis to better understand how the rate 13 structure is faring after implementation. As PG&E observes 14 various situations that are not ideal, it begins a list of potential 15 changes to rate design to propose in the next rate case to 16 temper or eliminate the problems. 17 18

ORA then asked PG&E to fully explain the reason(s) why PG&E 19

proposes the rate design changes only for residential customer class, and not 20

for any other classes.246 PG&E responds that there are structural deficiencies in 21

the residential rate design that have to do with the bundled tier ratio, the almost 22

all volumetric structure of residential rates, and the adopted throughput. PG&E 23

explains:247 24

The main reason why PG&E is proposing rate design changes for 25 the residential class is that there are structural deficiencies for 26 residential customers in comparison to other PG&E customers 27 with more stable rate designs throughout the year. The last two 28 BCAPs set a goal of a residential bundled tier ratio of 1.2, 29 however, the current illustrative annual bundled rate ratio is 1.41. 30 The increase of the residential bundled tier ratio was caused by 31 unforeseen changes in the procurement versus transportation 32 rate relationship, as described in Chapter 7 testimony. 33

244

ORA-08, Q1(c) data request.


246 ORA-08, Q1(d) data request.


62

1 Additionally residential rate design is the center of 2018 GCAP 2 proposals as the structure is not cost-based, but rather the 3 adopted residential rate design is almost all volumetric except for 4 the current $3 non-CARE minimum monthly transportation 5 charge. Purely volumetric rates inherently cause bill volatility as 6 temperature is a direct driver of residential customer usage, 7 inclining block rates enhance that impact, and inclining block rates 8 at ratios unintended in the previous decisions create situations of 9 excessive bill volatility. Using the 2010 BCAP throughput forecast 10 in setting current rates also is causing a structural issue of 11 undercollection as the temperature was higher than average for a 12 prolonged period of time in addition to not accounting for 13 continued energy efficiency per customer since the forecast was 14 developed in 2009. With an unintended Tier 2 to Tier 1 bundled 15 rate ratio as discussed in Chapter 7 testimony, the warmer than 16 normal weather and increased level of energy efficiency, 17 significant shortfalls in revenue collection resulted in higher 18 residential rates being implemented through PG&E’s AGT’s with 19 CFCA-Distribution undercollections of hundreds of millions of 20 dollars for several years. G-NR1, G-NR2, and G-NTD all have a 21 rate design more reflective of cost of service than residential rate 22 design, with a monthly customer charge and seasonal volumetric 23 rates that decline as usage increases which increases the ability 24 to set rates that is more likely to collect an amount of revenue 25 more comparable to the revenue requirements allocated to the 26 customer class, with potentially less impact from weather or 27 energy efficiency compared to cost of service. Understanding the 28 limits of CPUC staff, parties, and PG&E staff with other gas 29 ratemaking cases occurring within the same general timeframe, 30 PG&E prioritized the rate design proposals it presented in the 31 2018 GCAP to those it felt are in the most pressing need of being 32 addressed, and they all concern residential rate design. 33

34

ORA asked PG&E to explain the deficiencies identified in the existing 35

residential rate structure. PG&E identified those deficiencies below:248 36

• The current baseline structure contributes to bill volatility by 37 including the warmer months of November and March with the 38 three peak cold winter months of December to February when 39 calculating the current 5-month gas winter season baseline 40 allowance for each baseline territory. The Tier 1 allowance 41 calculated in a 5 month winter structure causes a greater share of 42

248

PG&E Response to data request ORA-08, Q.2(b).

63

the month’s usage to be billed under tier 1 rates in the warmer 1 November and March months leading to lower bills. The lower 2 bills then spike for many customers during the three peak winter 3 months (December to February) as the currently calculated winter 4 tier 1 allowance leads to a much higher percentage of the months 5 usage being billed in tier 2 than had been billed in tier 2 in 6 November and March. Customers then experience a double 7 whammy impact of both higher usage and more of that higher 8 usage being billed at a higher rate. 9 • The current tier ratio of 1.41 is excessive (and unintended) due 10 to the relationship between gas procurement rates and gas 11 transportation rates. Transportation rates have increased while 12 procurement rates have decreased leading to the underlying bill 13 volatility caused by normal changes in temperature across 14 months and for the same month across the years. 15 • The adopted residential rate design is almost all volumetric 16 except for the current $3 non-CARE minimum monthly 17 transportation charge (collecting around $5 million. Volumetric 18 rates inherently cause residential bill volatility as temperature is a 19 direct driver of usage for this customer class. 20 21

(a) PG&E’s Proposal for a 3-Month Winter 22 Baseline 23

PG&E’s proposal for a 3-month Winter Baseline includes a companion 24

proposal to shift both November and March into a new 9-month non-peak 25

season249 which, as explained in the next section, may have the unintended 26

consequence of increasing the average Residential customer bill when all 12-27

months are combined. ORA recommends that the creation of the 3-month peak 28

winter baseline should be in tandem with the creation of a two-month off-peak 29

winter season. The creation of the new two-month off-peak winter season is 30

explained in section (f).250

31

The Enhanced Tool PG&E developed at the Commission’s request 32

provides for only two choices regarding the Residential Baseline Allowance 33

Season Structure: a “0” represents Status Quo, meaning the 5 month winter 34

and the 7 month summer allowances updated in PG&E’s 2017 GRC Phase II 35

249


250 This section is supported by ORA witness R. M. Pocta.

64

while a “1” represents PG&E’s 2018 GCAP Proposal, meaning the 3 month 1

peak winter and 9 month non-peak allowances calculated using the same 2

historical period as 2017 GRC Phase II.251 For this reason, ORA’s 3

recommendation regarding the Residential Baseline Allowance Season 4

Structure could not be appropriately captured by the Enhanced Tool.252 5

Although the Enhanced Tool provides for a user-specified setting on the 6

“Allocation of Gas Base Distribution Revenue Requirement” so that ORA was 7

able to use Option setting “6” available as a user-specified setting for its Cost 8

Allocation Methodology recommendation, the Enhanced Tool does not have 9

user-specified settings for the Baseline Season Structure portion. ORA’s 10

recommendation is neither a “0” nor a “1” in the Scenario Settings. If the 11

Commission is persuaded by ORA’s recommendation on the creation of the 3-12

month Winter Baseline in tandem with the creation of a two-month Off-Peak 13

Winter season, then the Commission should order PG&E to include ORA’s 14

recommendation in the Scenario Settings for the Baseline Season Structure 15

before reaching a final decision. 16

(b) PG&E’s Proposal Unnecessarily 17 Increases Summer Baseline 18

PG&E’s proposal for a 3-month Winter baseline only and shifting both 19

November and March to summer unnecessarily increases the summer baseline 20

while decreasing the baseline quantities for the non-peak winter months of 21

November and March.253 The expected increases to the winter and summer 22

baselines associated with PG&E’s proposal are shown in PG&E’s 23

Workpapers254 and summarized by ORA in the Table below. 24

251

See PG&E’s Enhanced Tool at Tab “ScenarioSettings.”


253 PG&E’s Updated 2018 GCAP Workpapers for ERRATA dated Feb.15, 2018, as shown in

Chapter 7, Table 1-2 Excel File.

254 PG&E’s Updated 2018 GCAP Workpapers for ERRATA dated Feb.15, 2018, as shown in

Chapter 7, Table 1-2 Excel File.

65

ORA asked PG&E to explain what is meant by its “baseline season 1

structure.” PG&E explains:255 2

The “baseline season structure” is how months are defined in 3 terms of seasons, winter and summer. This would change the 4 baseline allowance for Tier 1 and Tier 2 based on the 5 methodology of calculating the baseline quantity for a month if 6 it is summer or winter (Summer has a threshold of 60% of the 7 average and Winter has a threshold of 70% of the average). 8 This is based upon the definition of “baseline quantity” from 9 Public Utilities Code 739(d)(1), where “baseline quantity” is 10 defined as “a quantity of electricity or gas allocated by the 11 commission for residential customers based on from 50 to 60 12 percent of average residential consumption of these 13 commodities, except that, for residential gas customers and for 14 all-electric residential customers, the baseline quantity shall be 15 established at from 60 to 70 percent of average residential 16 consumption during the winter heating season”. PG&E gives its 17 customer the highest baseline quantities possible by setting its 18 baseline quantities at the highest end of the range specified by 19 the law; that is, 60 percent of average usage for basic-electric 20 and all-electric customer in the summer, 60 percent of average 21 electric usage for combined gas and electric customer in the 22 winter, and 70 percent of average usage for gas and all-electric 23 customers in the winter. 24

25

The baseline season structure as described is said to be uniform across 26

PG&E’s residential gas customer class.256 The baseline amounts shown in 27

ORA Table 5-3 summarize the Present and PG&E’s Proposed Baseline Season 28

Structure as derived by PG&E from data on 30-year average monthly Heating 29

Degree Day (HDD) with a base temperature reference of 60.257 As indicated in 30

ORA Table 5-3, at line 3 of column B, PG&E’s proposal results in a 70 percent 31

increase over the Present amount of the Summer Baseline. However, this is a 32

decrease to the current baseline quantities for the winter months of November 33

and March. 34

255

PG&E Response to data request ORA-08, Q.3a.

256 PG&E Response to data request ORA-08, Q.3b.

257 Id. Chapter 7, Table 1-2 Excel file.

66

ORA Table 5-3 1 Reproduction of PG&E Workpaper Table 1-2 2

Summary of Present and PG&E’s Proposed Baseline Season Structure 3 Line No. Particulars Summer Baseline Winter Baseline

(a) (b) (c)

1 Present 46 271

2 Proposed 78 324

3 Percentage Increase

of Proposed over

Present

70%

20%

4 Amount of Increase

in Proposed over

Present

32

53

Source: Chapter 7, Table 1-2, PG&E’s Updated 2018 GCAP Workpapers for ERRATA 4 dated Feb. 15, 2018. 5

6

Under PG&E’s proposal, the Summer Baseline will increase from the Present 7

amount of 46 (at line 1) to the new proposed amount of 78 (at line 2). Further, 8

ORA Table 5-3 indicates at line 3 of column (c) that PG&E’s proposal results in 9

a 20 percent increase over the Present amount of the Winter Baseline. Under 10

PG&E’s proposal, the Winter Baseline will increase from the Present amount of 11

271 (at line 1) to the new proposed amount of 324 (at line 2). PG&E’s 12

workpapers show the baseline numbers presented in ORA Table 5-3 were 13

derived from the 30-Year average HDDs.258 The Table below shows the 30-14

Year average monthly HDD presented in PG&E’s Workpapers in support of 15

Chapter 7 of the GCAP testimony.259 16

Heating Degree Day (HDD) is a measure of how cold a location is relative 17

to, typically, a base temperature of 65 degrees Fahrenheit.260 PG&E’s 18

Workpapers indicate a base of 60 for the HDD.261 As shown in the HDD data in 19

the table below, during the summer months of April through October, the 20

average HDDs are lower amounts compared to the Winter months of November 21

258

Table 1-2 Excel File in PG&E’s Updated 2018 GCAP Workpapers for ERRATA dated Feb. 15, 2018.

259 Table 1-2 Excel File in PG&E’s Updated 2018 GCAP Workpapers for ERRATA dated Feb.

15, 2018.

260https://www.eia.gov/totalenergy/data/monthly/pdf/sec1_20.pdf

261 Id. Chapter 7, Table 1-2 Excel File.

67

thru March. The basis of the present baseline season structure are the average 1

HDD during the Summer months of April through October (shown on lines 4 2

through 10 of Table 5-4 below) and results in the amount of 46 while those for 3

the Winter baseline are based on the 30-year average monthly HDDs of 4

November through March (shown on lines 1 through 3 and lines 11 and 12). 5

The creation of the initial baseline quantities could be traced back to the 6

Warren-Miller Lifeline Act of 1976 that “required the California Public Utilities 7

Commission to create a ‘tiered’ system by designating a baseline quantity of gas 8

and electricity necessary to supply a significant portion of the energy of the 9

average residential customer at below-average cost, while additional usage 10

would be charged at above-average cost.”262 The Act is codified in California 11

Public Utilities Code § 739.263 The baseline statute is meant to provide an 12

energy allowance for basic energy needs at a lower rate and sets baseline 13

amounts between 60-70% of average household consumption during the winter 14

heating season for residential gas customers.264 15

ORA Table 5-4 Reproduction of PG&E Workpaper Table 1-2

Line No.

Month

30-Year Average HDD Using Gas Weights

1 Jan 355

2 Feb 264 3 March 183 4 April 123 5 May 65

6 June 28

7 July 12 8 Aug 11 9 Sept 19

10 Oct 63 11 Nov 196 12 Dec 354

Source: Chapter 7, Table 1-2, Excel File in PG&E’s Updated 2018 GCAP 16 Workpapers for ERRATA dated Feb. 15, 2018. 17

As indicated in ORA Table 5-3, the proposed amount of increase to the 18

Summer Baseline under PG&E’s proposal (shown on line 4 in HDD and on line 19

262

www.cpuc.ca.gov/General.aspx?id=12186 263

www.cpuc.ca.gov/General.aspx?id=12186 264

Public Utilities Code sec. 739.

68

3 as a percentage increase in ORA Table 5-3) over the Present is unnecessary 1

because customer gas usage is typically low during the summer months. Gas 2

usage is typically for space heating and there is normally no space heating 3

demand during the summer months. 4

(c) GCAP Enhanced Tool Shows 5 Disadvantages to Ratepayers 6

ORA’s run of PG&E’s GCAP Tool shows that November and March bills 7

are higher under the 3-month baseline proposal compared to the scenario under 8

the current 5-month baseline without any change to any of PG&E’s other 9

proposals except for the baseline. ORA performed various runs using the 10

PG&E GCAP Enhanced Tool.265 The results are discussed below. 11

Scenarios with PG&E GCAP Proposals were run using the GCAP 12

Enhanced Tool to compare results for ORA based on the same residential 13

baseline allowance season structure. Results indicate that PG&E’s GCAP 14

proposals based on the 3 months/9 months residential baseline allowance 15

season structure showed essentially the same number of months with potential 16

increases in average monthly bills when compared with ORA’s GCAP 17

Recommendation based on a similar 3 months/9 months residential baseline 18

allowance season structure. 19

But since the 3 months/9 months structure is not fully reflective of ORA’s 20

recommendation regarding the baseline season structure, PG&E’s GCAP 21

proposals based on the 3 months/9 months residential baseline allowance 22

season cannot be compared against ORA’s recommendation based on the 23

same scenario setting in the GCAP Tool. The results indicate that ORA’s GCAP 24

recommendations are only ahead by one month compared to PG&E’s proposal 25

if you count the number of months with potential decreases in average monthly 26

bills. 27

In a data request, ORA asked PG&E to provide analysis using the Tool to 28

show the reduction in bill volatility accomplished through PG&E’s proposals. In 29

265

Refer to ORA Attachments D, E, F, G, H, and I.

69

that request, ORA asked PG&E to identify what the 25th, 50th, and 75th percentile 1

rates would look like for the past 5 winter seasons starting with the 2012-2013 2

winter season through the 2016-2017 winter season under PG&E’s proposed 3-3

month winter plan.266 PG&E’s responses were provided in attachments to data 4

request ORA-20 Q.6 which will be included in ORA’s workpapers. PG&E 5

explains:267 6

The proposed dollar change impact of implementing PG&E’s 7 baseline season proposal for years 2012-2017 shows that, 8 generally, January and December bill levels will decrease and 9 March and November bill levels will increase. This means that 10 there will be less of an amount of change between the customer 11 bills before and after the months of March and November, thereby 12 decreasing the bill volatility and allowing the customer to receive a 13 slightly better price signal from their bills. However, this data set 14 does not show the decrease in bill level in the summer months 15 which occurs because the summer gas baseline allowances are 16 re-calculated with moving March and November from winter 17 months to summer months, and this increases the summer 18 allowances. Residential electric baseline season definition is 19 being reviewed in PG&E’s 2017 GRC Phase II rate case. Should 20 both of PG&E’s baseline restructuring proposals be adopted, dual 21 commodity bill volatility would be reduced as both proposals shift 22 cost recovery to the spring and fall months versus the peak winter 23 and summer seasons when most residential customers 24 experience their highest and most volatile changes of the year. 25

266

ORA Data Request ORA-20, Q.6.


70

(d) PG&E Concedes Its Proposal Could 1 Increase Customer Bills But Explains the 2 Goal Was to Reduce Bill Volatility 3

PG&E concedes in testimony that there will be increased bills during the 4

winter months of March and November.268 PG&E states:269 5

Increased bills during the shoulder months of March and 6 November under this proposal allows the moderation of 7 excessive bill volatility in peak months with more variable 8 temperatures and better aligns bills with cost of service. 9 10

ORA asked PG&E to provide a backcast for the period 2010 through 11

2017 based on the current 5-month winter baseline and assuming the proposed 12

3-month winter baseline had been in place during that same 8-year period.270 13

PG&E’s data response showing a backcast for the period 2010 through 14

2017 that indicates higher net bills for residential customers had PG&E’s 15

proposed 3-month winter baseline being in place during the 2010-2017 16

period.271 ORA presents a summary of those results below: 17

ORA Table 5-5 18 Summary of 8-Year Backcast Results 19

NET BILL DIFFERENCE 5 MONTHS Versus 3 MONTHS

Line

#

Territory 2010 2011 2012 2013 2014 2015 2016 2017

1 P $9.10 $9.02 $9.25 $8.00 $11.33 $9.65 $10.95 $9.22

2 R $7.29 $5.50 $6.71 $3.36 $6.64 $5.85 $5.57 $4.23

3 S $8.85 $7.05 $7.90 $4.22 $8.13 $7.39 $7.77 $5.60

4 T $10.16 $9.76 $9.34 $8.75 $10.75 $11.30 $10.96 $9.47

5 V $7.63 $6.69 $6.67 $6.91 $8.22 $9.20 $7.75 $7.09

6 W $6.17 $3.66 $5.38 $2.41 $5.41 $5.06 $4.80 $3.22

7 X $10.38 $9.25 $9.88 $6.89 $9.87 $10.08 $10.62 $7.92

8 Y $7.08 $7.29 $8.59 $7.35 $9.22 $8.84 $9.96 $8.80

Source: PG&E Response to data request ORA-15, Q.4(e), Atch 01. 20

The backcast PG&E performed for the period 2010 through 2017 21

indicates that, for each of the baseline territories shown, the net difference in 22

average bill over the same 5-month period results in positive amounts in 23

268



270 Data request ORA-15, Q.4(e).


71

average monthly bills. Based on the backcast and the resulting net difference in 1

average monthly bills, residential ratepayers in those baseline territories would 2

have paid more in their average monthly bills from November through March if 3

the 3-month winter baseline season had been in effect for the period 2010-2017, 4

instead of the current 5-month winter baseline season. 5

PG&E confirmed ORA’s analysis of the backcast, but informed ORA of 6

other considerations that were provided by PG&E to ORA in response to data 7

request ORA-15 Q.4(e), Atch 01 stating below in Supplemental Response:272 8

PG&E agrees that ORA’s analysis is correct in its analysis that 9 the net difference in the average bill over the same 5-month 10 period results in positive amounts, however, the goal of PG&E’s 11 3-month peak baseline season structure proposal is not to 12 decrease the winter bill level for all months in the current 5-month 13 winter but rather to address the peak months with a high bill level 14 and to smoothen bill volatility while not further complicating 15 customers bill additionally beyond the two season baseline 16 season structure in place today. PG&E provides additional 17 analysis below using PG&E’s attachment, 18 GasCostAllocationProceeding2018_DR_ORA_015_Q04e_atch01 19 (previously provided to ORA), which is the November to January 20 bills for years 2010 to 2017 for Average Residential Bundled 21 Individually Metered and the same information backcast with 22 PG&E’s 2018 GCAP 3-month peak winter proposal baseline 23 quantities. 24 25 ORA’s analysis is correct, but there are a few things to consider 26 regarding PG&E’s 2018 GCAP and these are: 27

a. the impact on the bill level of the 3 peak winter months, 28 b. the impact on bill level for summer months, 29 c. the impacts on the bills of customers with higher or lower 30

usage than average, 31 d. the impact on bill volatility, 32 e. the relationship with the peak and non-peak months of 33

PG&E’s electric bills, and 34 f. the consideration of temperature data for the time period. 35

36 The 2018 GCAP proposal of a 3-month peak winter baseline 37 season was proposed to combat bill volatility for the transition 38 from the summer to winter season to decrease the shock for 39

272

PG&E Response to data request ORA-15, Q.4(e), Supp01.

72

customers when they receive their first peak winter bill, and to 1 reduce peak winter bills and peak winter bill volatility for 2 customers typically not having usage billed in Tier 2, along with 3 sending better general price signals. 4 5 PG&E’s 2018 GCAP proposal of moving from a 5-month winter 6 to a 3-month winter peak is revenue neutral during normal 7 temperature years, which means that if the temperature is as 8 expected the revenue collected would meet the revenue 9 requirement used to calculate the proposed rates. The current 7 10 non-peak months, which in the 2018 GCAP proposal would also 11 move to 9 non-peak months including March and November, 12 would decrease in bill level except for March and November, 13 because nonpeak month baseline allowances would be higher 14 under the 3-month peak winter baseline structure as the summer 15 gas baseline allowances would be re-calculated to include the 16 gas usage from November and March, and thereby increasing 17 the amount of summer allowances. 18 19 For ORA’s analysis found in the attachment, Summary of 20 Response to ORA 15Q4eAtch1, ORA added up the 5-month 21 winter bill difference between the 5-month winter baseline 22 season structure and the 2018 GCAP proposal of the 3-month 23 peak winter backcast. However, the sum of the 3-month peak 24 winter bill level difference is a negative number, meaning that the 25 overall bills for December, January and February are lower with 26 the backcast of the proposed 3-month peak winter baseline 27 season structure. The backcast analysis demonstrates that 28 PG&E’s peak winter baseline structure proposal achieves its 29 intended results. 30 31 As mentioned above, there would be an increase in the March 32 and November bill levels once these months become non-peak 33 months and subsequent drop in the bill levels in the December to 34 February months, which leads to a muted bill volatility. The table 35 below 36 shows the average per baseline over years 2010 to 2017 of the 37 difference between the months of February to March and the 38 months November to December, and shows that with the 3-39 month proposal, the changes in bills are lower. 40

73

1 Baseline

Territor

y

Bill Diff. between March and February Bill Diff. December and November

Current Baseline Proposed Baseline Current

Baseline

Proposed

Baseline

P $ (22.04) $ (12.17) $ 34.91 $ 21.99

R $ (25.76) $ (19.56) $ 44.80 $ 34.88

S $ (28.22) $ (20.83) $ 51.53 $ 39.89

T $ (14.54) $ (9.27) $ 30.39 $ 23.11

V $ (11.41) $ (5.12) $ 29.80 $ 21.85

W $ (25.79) $ (20.03) $ 48.39 $ 38.59

X $ (24.89) $ (17.23) $ 47.66 $ 36.31

Y $ (21.44) $ (11.71) $ 41.73 $ 27.33

2 Another factor to acknowledge underlying the analysis of 3 implementing a 3-month peak winter baseline to replace the 5-4 month winter baseline is the consideration of historic temperature 5 data for the designated time period. If the temperature is warmer 6 than normal it suppresses the HDDs and the number of 7 customers moving into tier 2 during the peak winter months while 8 in colder than normal periods the opposite occurs. On average 9 over this eight-year recorded period of analysis, the 3-peak 10 month HDD’s were 2.5% lower than normal. While the 5-month 11 winter season HDD’s were 7% lower than normal over the 7 year 12 period of analysis, however, 3 years out of the 7 years illustrated 13 the impacts under colder than normal 5-month winter season. 14 Given these variances from normal, PG&E believes the analysis 15 provides reasonable insight into the impact in the future of the 16 proposed 3-month peak season baseline structure. 17 18 The data provided to ORA showed the customers with average 19 customer impact. However, as the Tool demonstrates, the 20 customers receiving the biggest benefit from the proposed peak 21 winter season structure are those between the 25th and 75th 22 percentile in annual usage as customers above or below these 23 break points generally either do not have usage billed in Tier 2 or 24 have a majority of their usage already billed in Tier 2. A majority 25 of PG&E’s residential bundled individually metered customers 26 are also electric customers, and are thereby dual commodity 27 customers. On a dual-commodity basis, the higher allowances in 28 the summer reduce gas bills during the peak months for electric 29 usage when most customers also have air conditioning turned 30 on, which increases their bills. Thereby the lowering of gas bills 31 in the summer will help smoothen out the dual commodity bill for 32 many customers. The graph below, found in the Enhanced 33 Residential Bill Impact Tool on tab Background_ Dual_ 34 Commodity, shows the current seasonality of the electric and gas 35 bills for non-CARE bundled residential individually metered gas 36 and electric customers over 2016 to 2017, with a very warm 37

74

winter. The Commission is also considering restructuring electric 1 residential baseline season in PG&E’s 2017 GRC Phase II 2 proceeding. 3 . 4

5 6 As PG&E’s response above shows, there could be any number of 7

considerations when looking at the question of restructuring the baseline 8

season. ORA’s recommendation offers bill relief in a way that is easier for 9

residential customer’s to understand. ORA’s recommendation minimizes the 10

average bill increases that otherwise would occur in the months of November 11

and March, as shown in the Backcast results confirmed by PG&E in response to 12

data request ORA-15 Q.4; PG&E confirms the increase in the average monthly 13

bill evident in the backcast for the period 2010-2017 noted by ORA in its 14

analysis. 15

PG&E explains that they were trying to moderate the increase in the 16

average bills between November and December when the customer may get a 17

bill shock from the higher winter usage that goes into Tier 2 rates. Since PG&E 18

has included November and March as part of the nine-month non-peak season, 19

there could also be increases in average bills during those months. ORA 20

recommends to not just create the 3-month Winter Peak, as PG&E proposes, 21

75

but to combine this 3-month Winter Peak with the creation of a 2-month Non-1

Peak Winter season, instead of a nine-month Non-Peak season as PG&E 2

proposes. This proposal will mitigate bill shock in the months of November and 3

March. ORA explains this in section (f) below. 4

(e) PG&E Has Not Explored All Options in 5 Seeking to Respond to Senate Bill 711 6 and May Risk Possible Higher Yearly 7 Customer Bill Totals If Its Focus Remains 8 on Moderation of Excessive Bill Volatility 9 Between November-December and 10 February-March 11

As indicated in PG&E’s Supplemental Response to data request ORA-15 12

Q.4(e), PG&E’s proposal was focused on addressing the peak months with a 13

high bill level and to smoothen bill volatility, as PG&E states:273

14

15 PG&E agrees that ORA’s analysis is correct in its analysis that 16 the net difference in the average bill over the same 5-month 17 period results in positive amounts, however, the goal of PG&E’s 18 3-month peak baseline season structure proposal is not to 19 decrease the winter bill level for all months in the current 5-20 month winter but rather to address the peak months with a 21 high bill level and to smoothen bill volatility while not further 22 complicating customers bill additionally beyond the two 23 season baseline season structure in place today. (Emphasis 24 added). 25 26

PG&E’s proposal was focused on trying to minimize the change in the 27

average monthly bill between November and December to reduce customer 28

shock with the high December winter bill as well as the change between 29

February and March. But as shown in the backcast results, the average bills 30

increased over the five-month period. PG&E says it was not trying to decrease 31

the winter bill for all the five months in the current winter baseline. 32

ORA’s reference to positive amounts in the backcast refers to this: On a 33

net basis, the net difference between the decreases in the average bills for the 34

273

PG&E’s Supplemental Response to data request ORA-15, Q.4(e).

76

months of December/January/February and the increases in the average bills 1

for the months of November/March, results in positive amounts, which indicate 2

that the increases outweigh the decreases in average monthly bills over the 3

entire 5 month period, based on the scenario where PG&E’s proposal on 3-4

month Winter Baseline is in place during the 2010-2017 period instead of the 5

current 5-month Winter Baseline. As indicated in ORA’s Table 5-5 on the 6

Summary of 8-Year Backcast Results, PG&E’s residential customers would 7

have consistently paid more on their average monthly gas bills on a net basis 8

over the 8-year period in each of the 8 Baseline territories shown in the table. 9

PG&E acknowledges that ORA’s analysis is correct but points out that the goal 10

of PG&E’s proposal is “not to decrease the winter bill level for all months in the 11

current 5-month winter.” PG&E’s proposal was focused on the moderation of 12

excessive bill volatility during the specific months when temperatures were 13

changing between November/December and February/March. But this singular 14

focus neglects the increase in average bills that will result over the five-month 15

period because PG&E’s 3-month proposal was in tandem with a nine-month 16

non-peak including March and November. 17

In data request ORA-15 Q.4(c), ORA asked PG&E whether PG&E’s 18

GCAP proposal is the same as the one presented in the California Senate 19

report, and if not, to explain the difference and provide a comparable table 20

similar to Table 2 from the California Senate report using the data and 21

information for the typical average bill for gas in PG&E’s territory.274 In 22

response, PG&E states:275 23

PG&E’s proposal is not exactly the same as the California Senate 24 Report illustration. PG&E’s proposal is exactly the same for the 25 three peak winter months of December, January and February. 26 However, instead of creating a two-month shoulder season 27 comprised of non-adjacent months of November and March 28 where customer bills would be further complicated by having at 29 least two and often three different baseline allowance amounts 30

274

Data Request ORA-15, Q.4(c).


77

used for each bill, as billing periods can normally be up to 34 days 1 depending on where weekends and holidays fall, PG&E proposes 2 to include the months of November and March with the current 3 “summer season” months of April to October and create a non-4 peak season of allowances. 5 6 As important as not adding to billing complexity for customers 7 who review their bill calculations, PG&E’s proposal further 8 reduces winter bill volatility by increasing November and March 9 bills compared to what they would be with the addition of shoulder 10 season baseline allowances. Two benefits of higher November 11 and March bills are (1) with the resulting higher summer gas 12 baseline allowances, PG&E’s millions of dual commodity 13 customers who use air conditioning in the summer will benefit 14 from slightly lower summer gas bills that under current summer 15 baseline allowance calculations. This has particular benefits for 16 households with more family members and the commensurate 17 need for more hot water for showers, laundry, and dishes. (2) It 18 sends an earlier signal to customers towards the end of 19 November that higher winter gas bills are right around the corner 20 and for households to be mindful of their usage prior to receiving 21 a necessarily high gas bill at the end of December when peak 22 winter is already well under way. 23 24

ORA’s review indicates that PG&E has left some options unexplored 25

such as including a cut-off in mid-month such as mid-November and mid-March 26

or some combination such as dropping November but keeping March or the 27

creation of a shoulder season. PG&E responds:276 28

PG&E explored different baselines along with the 29 recommendations received in Senator Hill’s SB 711 30 Recommendation Report. PG&E believes the 3-month winter 31 peak and 9-month summer baseline season is the best outcome 32 for all residential customers by maximizing peak season 33 allowances, minimizing implementation costs, and not causing 34 additional complication for customers in following their bills 35

However, PG&E has not explored the options of restricting the 36 season structure to include cut-offs at mid-month as that would 37 increase the complexity and cost of the IT implementation 38 changes required and complicate following bill calculations as 39 monthly pricing rates change on the 1st of every month and then 40 seasonal baseline allowances would change on the 15th. 41

276

PG&E Response to data request ORA-13, Q.4a-b.

78

Regarding the question of exploring shoulder month seasons, PG&E 1

responds:277 2

PG&E did not explore shoulder month seasons for three reasons: 3 4 • applying non-peak allowances to November has a greater 5 impact on reducing November to December bill volatility than 6 creating a third shoulder season baseline season that would apply 7 to the shoulder season consisting of March and November, 8 9 • it would take significant additional time and expense to create 10 additional baseline seasons versus reframing when the existing 11 two baseline seasons occur, 12 13 • And having a shoulder season would result in additional bill 14 complexity for customers as customers would experience multiple 15 baseline allowances in one bill four times a year instead of twice 16 and some customers with a longer billing period would have three 17 baseline allowances used to calculate one bill. 18 19 Therefore, as PG&E’s goal was to address peak winter month 20 bill volatility in the most cost-effective manner possible, 21 while limiting customer bill complexity, PG&E did not analyze 22 what the customer bill would be with an additional shoulder month 23 baseline season. Conceptually, creating a shoulder season would 24 not reduce November to December bill volatility as much since 25 November baseline allowances would be higher under a shoulder 26 season structure than under a non-peak structure and it would not 27 reduce summer gas bills. The 2018 GCAP proposal of the 3-28 month peak winter months only required changing when the 29 baseline season allowances changed while retaining two 30 seasons. (Emphasis added). 31 32

ORA’s recommendation on a two-month Off-Peak Winter season is 33

explained next. 34

277

PG&E Response to data request ORA-20, Q.1 Supp02.

79

(f) ORA Recommends a Three-Month 1 Peak and Two-Month Off-Peak Winter 2 Baseline Season 3

Issue Number 3 identified in the Scoping Memo and Ruling of Assigned 4

Commissioner and Administrative Law Judges is: 5

“Should PG&E’s proposals for changing the residential winter 6

baseline months to December, January and February, and for 7

placing the remaining months of the year in a non-peak baseline 8

season be approved?” 9

No, PG&E’s proposals should not be approved. ORA agrees with 10

changing the winter baseline months but not as proposed by PG&E. ORA 11

proposes a peak and off-peak winter season. The peak winter season would 12

include the months of December, January and February while the off-peak 13

winter season months would be the months of November and March. There 14

would be separate baseline quantities for the peak and off-peak winter seasons 15

and no change to the current summer baseline quantities or time frame. 16

ORA proposes to change the baseline quantity levels for the months of 17

December, January and February in a manner that is consistent with the change 18

proposed by PG&E. As stated above, these three months would be identified as 19

the peak winter baseline months. The peak winter baseline quantities for the 20

months of December through February are shown in Table 5-7. These baseline 21

quantities are consistent with those proposed by PG&E as shown in Table 5-8. 22

ORA opposes PG&E’s proposal to move the remaining winter months of 23

November and March in the non-peak summer baseline season. For many 24

years, November and March have been included in the winter heating season. 25

The months of November and March should be treated as off-peak winter 26

months and a separate baseline level be developed for these two months. 27

Table 5-6 shows the average heating degree days (HDDs) for the current 28

summer and winter months and the proposed summer and winter months as 29

recommended by PG&E. Table 5-6 shows the HDDs for the current summer 30

and winter months and the proposed summer, peak winter and off-peak winter 31

months as recommended by ORA. These tables show that the average HDDs 32

80

for November and March are significantly higher than the average HDDs for the 1

summer months of April through October. The average HDDs for November 2

and March exceed the average summer months HDDs by 300%. The average 3

residential customer usage and weather adjusted usage is provide in 4

Attachment L for the years 1995 – 2017. 5

The summary of heating degree data is in Attachment K. The total HHDs 6

for winter is 1352 for the present 5 month period of November – March which is 7

an average of 271 HDDs for this period as shown in Table 5-6. The HDDs for 8

the months of December – February is designated as the peak winter months by 9

ORA. The total HDDs for this period are 973 HDDs which amounts to 324 10

HDDs per month and is equivalent to approximately 72% of the HDDs in the 11

present 5 month period. 12

The months of November and March would be designated as non-peak 13

winter months. The number of HDDs for November and March are 379 HDDs 14

which is an average of 189 HDDs as shown in Table 5-6. The total 379 HDDs 15

amounts to 28% of the total HDDs for the current 5 month winter period. 16

PG&E’s proposal to move November and March from the winter baseline 17

months to the summer baseline months is a significant departure from the 18

current baseline structure that has been in place for many years because it 19

results in a significant reduction to the baseline quantities for those two winter 20

months. These reductions in baseline quantities and resulting increase in the 21

summer baseline quantities provide essentially no ratepayer value. The new 22

baseline summer quantities proposed by PG&E are less than 70% of the 23

average residential consumption for November and March. 24

The months of November and March are not analogous to summer 25

months. The ORA proposal to create an off-peak winter season for the months 26

of November and March: (1) will assure a reasonable baseline quantity for those 27

winter months and (2) is consistent with the Public Utilities Code which 28

contemplated “additional baseline seasons”278, i.e., ORA’s proposal is consistent 29

278

Public Utilities Code sec. 739 (a) (1).

81

with that directive. It will assure that residential customers will have reasonable 1

rates and gas bills in those months. 2

The Public Utilities Code states “the baseline quantity shall be 3

established at from 60 to 70 percent of average residential consumption during 4

the winter heating season”.279 November and March are within the historic 5

winter heating season. These months have been included in the winter heating 6

season since baseline quantities were developed. The gas usage in the months 7

of November and March are significantly higher than the summer months.280 8

The change proposed by PG&E will significantly lower the baseline levels for the 9

winter season months of November and March. Cold weather is common in 10

these two months as evidenced by the HDD data and residential customer 11

usage. To place these months into the summer baseline will lead to increases 12

in residential customer bills in those two months. There is little to no benefit to 13

customers by slightly increasing the summer baseline amounts. The summer 14

baseline months require no increase in baseline quantities. This time period is 15

when gas usage is generally lower especially during the months of June through 16

September. An increase in the baseline quantities especially the very warm 17

June through September time frame offers no customer value. Conversely, 18

placing the months of November and March in the summer season will result in 19

significantly higher bills in those 2 winter season months. 20

A few alternatives were considered for developing the baseline quantities 21

for the months of November and March based on the information and data 22

available. One option was a proportionate decrease relative to the proportionate 23

increase for the peak winter months to determine the new baseline quantities for 24

the off-peak winter months of November and March. This approach would use 25

the existing total baseline quantities for winter but modify the allocation of 26

baseline quantities between peak and off-peak months. For example, Baseline 27

Territory P currently has 58 therms per month for the 5 winter months for a total 28

279

Public Utilities Code sec. 739 (a) (1).

280 See Attachment L.

82

of 290 therms. ORA and PG&E propose that 64 therms per month be allocated 1

to the peak winter months of December – February which is a total of 192 2

therms. ORA considered allocating the remaining baseline quantities (290 – 3

192 = 98) to the off-peak winter months. This results in a baseline quantity of 49 4

therms per month for the off-peak winter months of November and March. 5

There is no change to the current winter baseline quantities but a reallocation of 6

the baseline quantities between the peak and off-peak winter months. This 7

would essentially retain a reasonable baseline quantity for residential customers 8

during for the cold non-peak winter months relative to past winter periods. 9

However, this approach does have limitations and for various reasons would 10

likely not work effectively from a modified rate design perspective.281 11

The proposed recommendation is to use average November and March 12

residential customer usage and develop baseline quantities directly from that 13

data. The data shows that the average residential usage for the 1995 through 14

2017 time frame is 51 therms for each of the months November and March for 15

the entire PG&E system.282

The system off-peak baseline quantity would be 16

set at 70% of the 51 therms or 36 therms. The most representative territory of 17

the system average would be Baseline Territory X. Baseline Territory X would 18

have the off peak winter baseline quantity set at 36 therms. This baseline 19

quantity is 64% of the current winter baseline quantity of 56 therms. The 20

baseline quantities for the other baseline territories are calculated at the same 21

64% of the current winter baseline quantities. These figures are shown in Table 22

5-7 and constitute ORA’s proposal for off-peak winter baseline quantities. 23

PG&E’s proposed baseline quantities are shown in Table 5-8. 24

281

ORA could not test its options since it does not have the resources to develop an independent cost allocation and rate design model.

282 See Attachment M.

83

Table 5-6 1 Present and Proposed Heating Degree Days 2

Present and PG&E Proposed (Heating Degree Days)

Summer Time Frame Winter Time Frame Present 46 Apr - Oct 271 Nov - Mar Proposed 78 Mar - Nov 324 Dec - Feb

Present and ORA Proposed (Heating Degree Days)

Summer Time Frame Winter Time Frame Present 46 Apr - Oct 271 Nov - Mar Peak Winter Proposed 46 Mar - Nov 324 Dec - Feb Off-Peak

Winter

Proposed 189 Nov & Mar

3 Table 5-7 4

ORA Proposed Baseline Quantities 5 Present vs. ORA Proposed Season Structure 6

7

Baseline Territory

G-1, G-S, G-T

Summer Winter

2017 GRC Ph. II

G-1, G-S, G-T

Summer Peak Winter Off-Peak Winter

2018 GCAP

P

Q

R

S

T

V

W

X

Y

12 58

18 56

11 50

12 53

18 48

18 51

12 46

15 56

21 71

12 64 37

18 62 36

11 57 32

12 60 34

18 53 31

18 54 33

12 53 30

15 62 36

21 78 46

Baseline Territory

GM

Summer Winter

2017 GRC Ph. II

GM

Summer Peak Winter Off-Peak Winter

2018 GCAP

P

Q

R

S

T

V

W

X

Y

9 26

16 21

10 30

9 18

16 30

15 35

8 23

10 21

12 26

9 29 17

16 23 13

10 34 19

9 20 12

16 33 19

15 37 22

8 26 15

10 23 13

12 29 17

8

84

Table 5-8 1 PG&E Proposed Baseline Quantities 2

Present vs. PG&E Proposed Season Structure 3 4

Baseline Territory

G-1, G-S, G-T Summer Winter 2017 GRC Ph. II

G-1, G-S, G-T Non-Peak Peak

2018 GCAP P Q R S T V W X Y

12 58 18 56 11 50 12 53 18 48 18 51 12 46 15 56 21 71

20 64 23 62 17 57 19 60 23 53 25 54 17 53 22 62 34 78

Baseline Territory

GM Summer Winter 2017 GRC Ph. II

GM Non-Peak Peak

2018 GCAP P Q R S T V W X Y

9 26 16 21 10 30 9 18 16 30 15 35 8 23 10 21 12 26

11 29 18 23 13 34 11 20 18 33 19 37 10 26 12 23 19 29

5

3. ORA Recommendation on the Tier Ratio 6

ORA does not oppose PG&E’s proposed phased-in return to residential 7

bundled tiered rate ratio to a goal of 1.2 to 1. 8

PG&E proposes to reduce the residential tier differential ratio over a 4-9

year period with gradual reductions to the bundled ratio from the current 1.41 10

ratio.283 PG&E proposes that the first step in the reductions would begin with 11

the implementation of the GCAP decision.284 According to PG&E, the initial 12

reduction would be followed by additional reductions to the ratio of 0.05 annually 13

283



85

in the Annual Gas True-Up (AGT) advice letter filing until the effective bundled 1

rate ratio reaches 1.20.285 2

ORA’s recommendation is based on the review of PG&E’s proposal which 3

indicates the following: 4

(a) The Inverted Residential Tier Structure is 5 Legislatively Mandated 6

The inverted residential rate structure is legislatively mandated pursuant to 7

Public Utilities Code Section 739.7 to encourage conservation and keep rates 8

reasonable.286 However, the Commission found that the Legislature continued to 9

express concerns about the bill volatility associated with inverted rates.287 10

The Commission balances the intentions of the mandate with the focus of 11

basing rates on cost and minimizing subsidies.288 In D.93-06-087, the Commission 12

found that a flatter tier structure promotes economic efficiency goals of rate design 13

and is more equitable because it reduces built-in subsidies.289 This indicates that 14

the Commission determines the tier differential that achieves this balance on a case 15

by case basis and weighing other factors that will affect rates. 16

(b) Historical Record Indicates Widening of 17 Differential between Tiers 1 and 2.290 18

PG&E’s testimony explains the history behind the settlement agreement 19

of its bundled residential tier rates adopted in D.05-06-029.291 PG&E explains 20

that the ratio of the transportation portion of the rates was set at 1.6 to 1 as long 21

as a bundled ratio of at least 1.2 to 1 was achieved.292 According to PG&E, the 22

285

PG&E GCAP Testimony, p. 7-11

286 Finding of Fact #26, D.93-06-087, p. 56. See also discussion in D.93-06-087, pp. 19-21.

Also, refer to Public Utilities Code Section 739.7.

287 Finding of Fact #26, D.93-06-087, p. 56

288 D.93-06-087, p. 56. See also discussion in D.93-06-087, pp. 19-21.

289 Finding of Fact #29, D.93-06-087, p. 56.

290 Table 7-7, p. 7-10, PG&E GCAP Testimony.



86

last two BCAPs set the residential bundled tier ratio at 1.2 to 1, but the current 1

ratio is now at 1.41.293 PG&E’s Table 7-7 in its GCAP testimony presents the 2

absolute value of residential tier differential compared to the gas procurement 3

rate.294 This indicates the widening of the tier differential showing that the tier 4

differential amounted to only 44 percent of the residential gas procurement, but 5

has increased to over 100 percent since early 2015.295 6

(c) The Current Ratio of 1.41 is Excessive 7 But May Be An Unintended Consequence 8 of Market Dynamics & Some Forces 9 Beyond PG&E’s Control296 10

The current ratio of 1.41 is a consequence of the ratio struck in the 11

settlement agreement in the last BCAP, movements in gas procurement prices, 12

and PG&E’s gas transportation rates. Gas procurement rates have been 13

declining since the peak prices reached in July 2008.297 On the other hand, 14

PG&E gas transportation rates have been on a rising trend.298 The gas 15

procurement rates are added to both Tier 1 and Tier 2 gas transportation rates 16

on an equal cents per therm basis.299 Application of the adopted 1.6 ratio of Tier 17

2 to Tier 1 residential transportation rates now results in a bundled rate ratio of 18

1.41. PG&E states that the ratio reached a high of 1.51 in May 2015.300 When 19

compared to the original goal of 1.2 in the adopted settlement, the current ratio 20

of 1.41 is excessive, but appears unintended because of the contributing factors 21

from the movements in the gas commodity prices and PG&E gas transportation 22

rates that caused a change in the relationships of the gas procurement rates 23

293

Response to data request ORA-08, Q.1(d).




297 Refer to commodity gas price trend shown in ORA Attachment A.

298 Refer to PG&E gas transportation rates trend in ORA Attachment B.


300 PG&E Response to data request ORA-08 Q.2c. See also Table 7-9, PG&E GCAP

Testimony, p. 7-13.

87

and the gas transportation rates. The gas commodity price movements could 1

not have been anticipated since these are the result of dynamic forces in the US 2

gas market. The rise in PG&E’s gas transportation rates is the result of a 3

combination of factors, some of which were beyond PG&E’s control as 4

described in testimony.301 A high current ratio is said to contribute to excessive 5

bill volatility.302 6

As shown in ORA’s Attachment A regarding the commodity gas price of 7

PG&E’s procurement rates, which are bundled in residential rates for the period 8

January 2005 through December 2017,303 there has been a declining trend in 9

the gas commodity component from the high levels reached in July 2008 until 10

today. 11

As shown in ORA’s Attachment B, PG&E’s gas transportation rates for 12

the period January 2005 through December 2017 indicate a rising trend from the 13

levels in 2005. 304 14

ORA does not oppose the phase-in return of the residential bundled tier 15

to a goal of 1.2 over four years. PG&E clarified that the four-year phase-in 16

reductions pursuant to the residential bundled tier ratio goal of 1.2 are executed 17

by the macros in PG&E’s Rate Design model.305 PG&E explains how the tier 18

ratio goal of 1.2 is achieved over a four year period: 19

The goal is achieved through a macro, which is the blue 20 “Calculate” button which goes through several iterations of 21 calculating what the transportation tier ratio needs to be so that 22 the bundled tier ratio is equal to the number chosen in cell D360. 23 This method with the macro is more efficient and more precise 24 than the manual method of finding the value of the transportation 25 tier ratio to get the subsequent bundled tier ratio which is the goal 26 stated in D360. 27

301


302 PG&E Response to data request ORA-08, Q.1d.

303 Available from PG&E’s website postings of historical rates.

304 Available from PG&E’s website postings of historical rates.

305 PG&E clarification via emails exchanged between ORA witness Pearlie Sabino and PG&E’s

witness assistant Johanna Fors dated May 3, 2018 regarding how the macros enable the achievement of the residential bundled tier ratio phased-in goal of 1.2 over four years.

88

4. ORA Recommendation on Non-CARE 1 Residential Minimum Transportation Charge 2 Increase 3

PG&E proposes to reduce volumetric transportation rates by increasing 4

the non-CARE residential minimum monthly transportation charge to $15 while 5

continuing to exempt PG&E’s CARE residential customers from the minimum 6

monthly transportation charge.306 7

PG&E’s proposal seeks “a reasonable adjustment in the degree of the 8

intra-class subsidies by reshaping several dimensions of residential rate design 9

while leaving residential CARE customers exempt from the increased minimum 10

monthly transportation charges proposed.”307 11

ORA does not oppose PG&E’s request to increase the non-CARE 12

residential minimum transportation charge, but ORA disagrees with the 13

magnitude of the increase sought by PG&E. PG&E’s request, if adopted, would 14

raise the current $3 minimum transportation charge308 by five times the current 15

level, or a 500 percent increase to the current charge. ORA recommends that 16

the Commission deny PG&E’s unjustified request for a 500 percent increase to 17

the Non-CARE residential customer’s minimum monthly transportation charge to 18

$15 a month from the current level of $3 a month. Instead, ORA recommends 19

that the Commission raise the current level of $3 a month to a marginal cost-20

based amount of $4 a month. This recommendation is based on ORA’s review 21

indicating the following: 22

(a) The Calculation of Monthly Non-23 CARE Residential Customer Costs 24

The Commission’s decision on PG&E’s cost allocation methodology 25

request could impact the amount of monthly residential customer costs for 26

purposes of the gas distribution revenue allocation. The calculations involved in 27

the monthly minimum residential transportation charge are shown below based 28

306

PG&E GCAP Testimony in A.17-09-006 (Revised for Errata), pp. 7-14 through 7-18.

307 PG&E Response to data request ORA-08, Q.2e.

308 D.05-06-029, Finding of Fact #2, p. 24.

89

on PG&E’s calculations reflected in PG&E’s Rate Model.309 These are the exact 1

same steps involved in the calculation for ORA’s recommendation. For the 2

meter + module customer cost, PG&E’s calculation results in the amount of 3

$10.65 at line 11, while ORA’s calculation results in the amount of $2.76 at line 4

11. 5

1 Total Customer Function Allocated to Residential Class ($000) 2 Meter + Module Proportion of Customer Function 3 Meter + Module Portion of Customer Functions 4 Multiply by % of Customer Function Associated with IM Meter by Segment 5 Individually Metered Customer Function: Meter + Module Portion 6 Forecast No. of Individually Metered Customers 7 Percentage of Individually Metered Meter Segment 8 Applicable Customers 9 Annual Customer Function Cost for Meter + Module portion per IM Res Customer 10 Divide by 12 11 Monthly Customer Function Cost for Meter + Module per IM Res Customer

6

Likewise, the calculation of the Revenue Cycle Services (RCS) costs 7

involve the same steps as shown below. PG&E’s calculation results in the 8

amount of $5.49 at line 7 while ORA’s calculation results in the amount of $1.42 9

at line 7. 10

1 Total Annual Customer Function allocated to Residential Class ($000) 2 Less Meter + Module Portion 3 Annual RCS Portion 4 Total Residential Customers 5 Annual RCS Costa per Residential Customer 6 Divide by 12 7 Monthly RCS Costa per Residential Customer

11

When these results are combined, PG&E’s calculation shows the total 12

monthly average cost of serving the applicable individually metered customers 13

amounts to $16.14 a month. On the other hand, ORA’s calculation shows a 14

different combined result of $4.18. 15

The factual basis for PG&E’s proposed monthly customer costs to Non-16

CARE residential customers initially indicated approximately $17.80 in customer 17

309

See PG&E’s GCAP Workpapers Updated for Errata 02152018 in the PG&E RD Model at Tab “Res_MinTransChargeLevel” at cell G17. This model is based on PG&E’s GCAP proposals.

90

monthly costs on the basis of an embedded cost methodology.310 However, the 1

Errata in PG&E’s GCAP Workpapers eventually showed customer monthly costs 2

of approximately $16.14 a month.311 PG&E proposes to impose a monthly 3

minimum transportation charge of $15 under a proposed embedded cost 4

allocation.312 5

If a MC methodology were retained and adopted for cost allocation as 6

ORA recommends, and given ORA’s DTIM-based MDCC cost estimate and the 7

MCAC NCO cost estimate, the results of ORA’s calculations in the PG&E’s Rate 8

Model indicate Marginal Customer costs to be in an amount appropriate for a 9

minimum monthly transportation charge to Non-CARE residential customer cost 10

of approximately $4 per month.313 The exact amount shown in the Rate Model 11

is $4.58 a month per non-CARE residential customer.314 12

As explained above, the calculation of ORA’s recommendation is derived 13

in the same way as PG&E’s proposal, except that ORA’s inputs are based on 14

marginal cost-based methods while PG&E’s inputs are based on embedded 15

cost methods. In addition, it is notable that ORA’s residential customer count is 16

the same as PG&E’s given the ORA witness’ recommendation on the forecast 17

customer count.315 Based on ORA’s recommendation on the cost allocation 18

methodology, the calculations show a monthly customer function cost for Meter 19

+ Module per individually metered residential customer cost in the amount of 20

$3.02 a month.316 In addition, the calculations on the monthly revenue cycle 21

310

PG&E Responses to data request ORA-08, Q.6(d)&(e).

311 See PG&E’s GCAP Workpapers Updated for Errata 02152018 in the PG&E RD Model at Tab

“Res_MinTransChargeLevel” at cell G26. This model is based on PG&E’s GCAP proposals.

312 See PG&E’s GCAP Workpapers Updated for Errata 02152018 in the PG&E RD Model at Tab

“Res_MinTransChargeLevel” at cell G26. This model is based on PG&E’s GCAP proposals.

313 See ORA’s GCAP Workpapers in the PG&E-provided RD Model at Tab

“Res_MinTransChargeLevel” at cell G26. This model is based on ORA’s recommendations.

314 Id.

315 Ex. ORA-02 by ORA witness T. Renaghan.

316 See ORA’s GCAP Workpapers in the PG&E-provided RD Model at Tab

“Res_MinTransChargeLevel” at cell G26. This model is based on ORA’s recommendations.

91

costs per residential customer indicate the amount of $1.56 a month. These 1

costs are combined to derive the total average monthly cost of serving 2

applicable individually metered residential customers of $4.18 (i.e., $2.76 + 3

$1.42 = $4.18). 4

On the other hand, calculation of the same cost on the basis of PG&E’s 5

EC proposal yields an amount for the monthly customer function cost for Meter 6

+ Module per individually metered residential customer cost in the amount of 7

$10.65 a month.317 In addition, PG&E’s calculations on the monthly revenue 8

cycle costs per residential customer indicate the amount of $5.49 a month.318 9

These costs are combined to derive the total average monthly cost of serving 10

applicable individually metered residential customers of $16.14 (i.e., $10.65 + 11

$5.49 = 16.14).319 12

Another way to view an increase to the current amount of the non-CARE 13

residential minimum transportation charge of $3 a month is to find out what the 14

new amount at today’s price level would be if the $3 charge were subject to the 15

inflation rate every year since it was established. The $3 a month charge was 16

adopted in D.05-06-029 for the PG&E 2005 BCAP and associated settlement.320 17

The CPI-based inflation rates are available from the Bureau of Labor Statistics 18

(BLS) website where one can find not just the CPI data but an easy to use CPI 19

inflation calculator to find the equivalent buying power of any chosen amount in 20

US Dollars from a certain specified month and year to another specified month 21

and year.321 Using the BLS calculator, ORA specified the amount of $3 in June 22

317

PG&E’s GCAP Workpapers Updated for Errata show the amount of $10.65 a month at cell G17 in the PG&E RD Model at Tab ““Res_MinTransChargeLevel.” ORA believes the amount indicated in PG&E Response to ORA-13 Q06(j) stating the amount of $11.74 of service line, regulator, meter, and module costs and $6.06 of revenue cycle services costs may be in error because the combined total would be $17.80 a month. The Response may not have been updated to reflect the amount shown in Workpapers.

318 Id.

319 Id.

320 D.05-06-029, Finding of Fact #2 and Ordering Paragraph #2.

321 https://www.bls.gov/data/inflation_calculator.htm

92

2005 and the date March 2018 and clicked on the calculate button.322 The BLS 1

calculator indicates that $3 in June 2005 has the same buying power as $3.85 in 2

March 2018. CPI data is also available for download from the BLS website if one 3

wants to verify the calculations for oneself.323 4

(b) Customer Bill Impacts Show A Large 5 Percentage of Non-CARE Residential 6 Customers Could Experience As Much 7 As a 35% Increase in Average Monthly 8 Bills 9

Under PG&E’s proposal, CARE residential customers would continue to 10

be exempt from the minimum bill and 93% will probably experience an average 11

bill decrease.324 The decrease for CARE residential customers could range 12

anywhere from a 1 percent decrease to 3 percent decrease in their average 13

monthly bills. That could mean a decrease in the CARE average monthly bill of 14

anywhere from 34 cents up to $6.30 a month. A number of CARE customers 15

(approximately 7%) may see an increase in their average monthly bills.325 The 16

increase could range from between a 1 percent to a 14 percent change in the 17

average monthly bill.326 That could mean an increase in the CARE average 18

monthly bill of anywhere from 26 cents up to a $3.17.327 19

On the other hand, PG&E’s proposed $15 minimum bill for residential 20

transportation rates will impact at least 58% of total residential customers 21

(CARE and Non-CARE) and at least 73% of Non-CARE Residential customers 22

322

As of the date ORA used the BLS calculator, the month of April 2018 could not yield a calculation yet. The BLS calculator could only provide up to March 2018.

323 https://data.bls.gov/pdq/SurveyOutputServlet.

324 See Table 7-13, PG&E Testimony. This is also shown in PG&E’s GCAP Workpapers

Updated for Errata 02152018 in the Excel File “ResBillImpactJul2017GRC2017vsOct2018GCAP2018_Feb16Errata” at Tab “Care_Feb16_2018” showing Table 7-13 for the distribution impacts on Residential CARE customers.

325 See Table 7-13 shown at lines 1 through 4 in the last column marked “Cumulative % of Total

G-1 CARE Customers,” PG&E GCAP Testimony, p. 7-20.

326 Id.

327 Id.

93

who will experience bill increases in their average monthly bills anywhere from 1

4% up to 35%.328 Specifically, cell I18 of the PG&E GCAP Workpaper for the 2

Non-CARE residential customers, demonstrates the cumulative percentage of 3

this customer class who will experience a change in the average monthly bill, 4

anywhere from 4% up to 35%.329 As shown in PG&E’s GCAP Workpapers, the 5

average bill change could increase in the range anywhere from an additional 6

$1.65 a month up to $7.69 a month. 7

Unfortunately, the information shown in PG&E Tables 7-12 and 7-13 8

cannot be replicated for ORA’s recommendation. ORA understands that these 9

tables were not created as part of PG&E’s Rate Model and were separately 10

generated through what is referred to as a SAS program.330 11

As indicated in PG&E’s discovery response, PG&E’s proposal may have 12

the most impact on non-CARE Residential customers who do not meet the 13

monthly minimum transportation charge. PG&E states:331 14

PG&E’s proposal will have the greatest impact on the bills of 15 non-CARE residential customers who do not meet the minimum 16 monthly transportation charge and to the degree they do not 17 meet the minimum monthly transportation charge for each 18 month. As minimum monthly transportation charges, the 19 proposal will only impact non-CARE customers during months 20 when their transportation charges are not high enough to 21 contribute to paying the costs of service reflected in the 22 proposed minimum charge. For non-CARE residential 23 customers who do not meet the minimum monthly transportation 24 charge after the transportation charge ((to put it simply: 25 transportation rate for non-CARE customers * customer usage) 26 has been calculated, the difference is added to the customer 27 transportation charge so that the customer is paying the 28

328

See Table 7-12, PG&E Testimony. This is also shown in PG&E’s GCAP Workpapers Updated for Errata 02152018 in the Excel File “ResBillImpactJul2017GRC2017vsOct2018GCAP2018_Feb16Errata” at Tab “NonCare_Feb16_2018” showing the distribution impacts on Non-CARE Residential customers.

329 This is also shown in PG&E’s GCAP Workpapers Updated for Errata 02152018 in the Excel

File “ResBillImpactJul2017GRC2017vsOct2018GCAP2018_Feb16Errata” at Tab “NonCare_Feb16_2018” showing the distribution impacts on Non-CARE Residential customers.

330 PG&E Response to data request ORA-015, Q.3(k).

331 PG&E Response to data request ORA-08, Q.05(g).

94

minimum monthly transportation charge. Please see the 1 response for part (d) above for further information. 2 3

The information from PG&E’s Rate Design Model shows that there are 4

approximately 256,000 Non-CARE residential customer bills in a month that are 5

below the minimum $3 bill on the transportation charge.332 An increase in the 6

minimum bill will augment the annual incremental revenue removed from the 7

volumetric transportation rate. 8

(c) ORA Results of the GCAP 9 Enhanced Tool Scenario Runs 10

11 ORA’s run of the PG&E GCAP Enhanced Tool for various scenarios indicates: 12 13

1. PG&E’s GCAP Proposals: the Model Scenario Settings in the Tool were 14

set to reflect all of PG&E’s GCAP proposals. These include EC allocation 15

and PG&E’s updated throughput, as well as the PG&E Baseline Season 16

Structure proposal for the creation of the 3-month winter peak and the 9-17

month non-peak, the residential bundled tier ratio phase-in return to 1.20, 18

the proposed $15 a month Non-CARE Residential minimum 19

transportation charge, and the proposed new super peak user charge of 20

$45 a month. 21

22

2. ORA’s Recommendation: ORA made changes in the Model Scenario 23

Settings to Reflect ORA’s recommendations to the greatest extent 24

possible. These include using a user-specified setting for the MC for the 25

Allocation of the Gas Base Distribution Revenue Requirement which was 26

selected as “Scenario 10.” However, ORA’s Baseline season 27

recommendations on the creation of the two-month Off-Peak Winter 28

Season in combination with the 3-month Winter Peak season cannot be 29

reflected in the GCAP Tool because there were no provisions in the Tool 30

for a user-specified setting on the Baseline Structure.333 There were only 31

two choices in the Tool regarding the Baseline season structure: 0 = 32

retain status quo 5month/7month season or 1 = PG&E’s proposed 33

3month/9month season. ORA agrees with the proposed creation of a 3-34

332

See PG&E’s GCAP Workpapers Updated for Errata 02152018 in the PG&E RD Model at Tab “Res_MinMoTransBillRev” at cell B32.

333 PG&E Response to ORA-33, Q.6.

95

month winter peak but does not agree with the 9-month non-peak. The 1

GCAP Tool has no provision for a user-specified setting on the Baseline 2

Season structure other than the two choices described. Hence, the 3

GCAP Tool does not appropriately reflect ORA’s recommendation on the 4

Baseline Season Structure. ORA’s run of the GCAP Tool selected “1” for 5

Baseline Season Structure but as explained in Section III.B.2, this does 6

not appropriately reflect ORA’s recommendation. 7

8

3. As shown in ORA Attachment I, which summarizes the 12-months data 9

shown in the GCAP Tool Bill Impact Dashboard for ORA compared to 10

PG&E’s proposals on a combined basis, ORA’s recommendations will 11

result in essentially no change in average monthly bills. A summary of 12

the total 12-months data from the GCAP Tool is reproduced in the table 13

below. Note that as explained above, ORA’s recommendation regarding 14

the Baseline Season Structure is not appropriately reflected by the GCAP 15

Tool. PG&E’s 3-month winter peak and 9-month non-peak cause the bill 16

increases in November and March. This was shown by ORA in the 17

backcast summarized in ORA Table 5-5 as requested by ORA from 18

PG&E for the period 2010-2017. PG&E confirmed ORA’s analysis on the 19

backcast. ORA expects its recommendations will reflect even better 20

results if the GCAP Tool had available options for user-specified Baseline 21

Season Structure. 22

ORA Table 5-9 23 Comparative Summaries from GCAP Tool Shown in ORA Attachment I 24

12-Mon Total Summary

Avg Mo. Bills: 50th Percentile ORA PG&E DIFFERENCE ORA >

PG&E

Present $616.50 $616.50 $ -

Current Proposed Scenario $619.53 $612.85 $6.68

Non-CARE Bundled $3.02 $(3.65) $6.68

CARE Bundled $0.41 $(8.05) $8.46

% Change 3.81% 3.93% -0.12%

Territory X Non-CARE: 25th Percentile Change $12.55 $20.68 $(8.13)

Territory X Non-CARE: 75th Percentile Change $(22.97) $(40.89) $17.92

Territory X CARE: 25th Percentile Change $6.26 $1.52 $4.55

Territory X CARE: 75th Percentile Change $(4.95) $(16.84) $11.39

25 Source: 12-Month Summary of Excel Range Row C79 through P90, Tab Bill Impact Dashboard, from ORA & PG&E GCAP ENHANCED 26 TOOL AT Scenario Settings described. 27

96

(d) PG&E Seeks Recovery of Gas 1 Transportation Costs Beyond 2 Fixed Customer-Related Costs 3

PG&E has indicated that its proposed minimum transportation charge 4

could be asking to recover beyond fixed customer-related costs of gas 5

distribution. PG&E states:334 6

PG&E proposed to increase the minimum transportation charge 7 from $3 to $15 as all costumers [sic] need to contribute 8 minimally to help pay for transportation services The annual 9 revenue collected with the current $3 minimum transportation 10 charge amounts to only $5 million out of the proposed 11 residential allocation of GRC Phase I gas revenue requirements 12 of $850 million in customer function costs and $500 million of 13 distribution costs, as well as an additional $300 million in local 14 transmission function cost allocation. The main deficiency is that 15 not all customers who benefit from the gas transportation 16 infrastructure are fully paying their fair share of the cost. Please 17 see Chapter 7, page 7-16, in PG&E’s 2018 GCAP Testimony. 18 19 The calculation of the minimum transportation charge on residential non-20

CARE customers should be based on the customer function allocated to 21

residential non-CARE customers, as appropriately shown in the PG&E RD 22

Model at Tab “Res_MinTranspChargeLevel,” which includes the meter and 23

modules cost allocated to residential non-CARE customers as well as the 24

annual RCS allocated to residential non-CARE customers. To justify a 25

proposed increase in the minimum transportation charge on residential non-26

CARE customers on the basis of a “need to contribute minimally to help pay for 27

transportation services” and argue that residential customers should pay more 28

of their fair share instead of “only $5 million out of the proposed residential 29

allocation of GRC Phase 1 gas revenue requirements of $850 million in 30

customer function costs and $500 million of distribution costs, as well as an 31

additional $300 million in local transmission cost” ignores the result of the PG&E 32

RD Model. ORA’s cost allocation recommendations, combined with ORA’s rate 33

design recommendations, result in the appropriate amount of the minimum 34

334

PG&E Response to data request ORA-08, Q.5(b).

97

transportation charge for non-CARE residential customers that is on the basis of 1

the customer function allocated to the non-CARE residential customer. The 2

volumetric gas transportation rate is where PG&E should be recovering 3

distribution function costs and any local transmission function costs. 4

5. ORA Recommendation on Super-User Charge 5

PG&E proposes to further reduce residential volumetric transportation 6

rates.335 This proposed reduction is achieved by creating a second-tier non-7

CARE minimum monthly transportation charge of $45 for the top percentage of 8

individually-metered residential customers.336 These customers are described 9

as those who have very high maximum daily peak gas therm consumption 10

associated with meters with greater capacity and cost than the normal 11

residential meters.337 The proposal would be implemented for the top 2-3 12

percent of Non-CARE residential customers with usage requiring more 13

expensive commercial-sized regulators and meters.338 The Super-User Charge 14

is proposed for those in the top tier of Non-CARE Residential customers defined 15

as those whose daily usage in the last 12 months is at least 15 therms a day.339 16

PG&E clarified that the Super-User Charge would not apply to the master 17

metered residential customer, only to the individually metered residential 18

customer.340 19

ORA does not oppose the concept of a super-user charge on the top tier 20

of individually metered customers who are said to be more expensive to serve. 21

A higher super-user charge could be a deterrent to high consumption and is 22

consistent with the state’s environmental goals. However, ORA disagrees with 23

the amount of PG&E’s proposal on the Super-User Charge. Given that no 24

335





339 PG&E Response.to data request ORA-15, Q.2(e).


98

customer surveys or consultations have been conducted by PG&E regarding 1

either the $15 minimum transportation charge or the new $45 super-user 2

charge, there is no way to predict customer reaction to this new charge.341 So, 3

a very steep initial charge for the super-user charge could encounter a negative 4

customer reception if it is not well understood. 5

ORA recommends an appropriate warning period before customers are 6

subject to the super-user charge. For example, a customer may not be aware 7

that he had used far too much gas on a certain month when there was an event 8

at his house. Could that one time event of high usage land them in the top tier 9

of users? PG&E has indicated in discovery that it will notify customers in 10

targeted communications through bill notifications about the changes in policy. 11

However, ORA is unsure whether this would be sufficient to educate the 12

customer or serve as appropriate warning before implementation.342 13

ORA recommends that the amount of the new Super-User Charge be a 14

more reasonable marginal cost-based rate of $12 a month.343 15

The list of customers identified in the top tier should be periodically 16

revisited. PG&E’s proposal should be further developed to identify the criteria for 17

a residential customer to be removed from the top tier list once they are on it, 18

and thus avoid the Super User Charge. 19

6. ORA Recommendation on Finding 20 Reasonableness of Rates 21

Based on ORA’s review as discussed in Sections III.A and B, ORA 22

respectfully recommends the Commission find that a DTIM-based MDCC 23

estimate and NCO MCAC marginal costs would result in the most reasonable 24

revenue allocation for PG&E’s customers and in the lowest reasonable cost-25

based rates for residential customers. As shown in ORA Attachment J, the 26

comparison of class average rates and residential bill impact, ORA’s 27

341

PG&E Response to data request ORA-15, Q.1(h).


343 See ORA GCAP Workpapers.

99

recommendation would result in the most reasonable revenue allocation for 1

PG&E’s customers and in the lowest cost-based rates for residential customers. 2

7. ORA Recommendation to Incorporate the Most 3 Recently Approved Future GT&S Throughput 4 Forecasts Into The Then Effective GCAP 5 Allocations in a Tier 2 Advice Filing 6

PG&E proposes to incorporate the most recently approved future GT&S 7

throughput forecasts into the then effective GCAP allocations via a Tier 2 advice 8

filing.344 According to PG&E, “PG&E’s proposal to adopt the throughput 9

forecasts in its GT&S rate cases for future GCAP allocations, prevents the 10

throughput used in GCAP ratemaking from becoming stale.”345 ORA does not 11

oppose this proposal. 12

Regarding when PG&E’s 2018 GCAP proposals will be implemented, 13

PG&E explains its implementation plan as follows:346 14

c) As filed, PG&E’s proposals would all be implemented on 15 October 1, 2018, except for the phased-in residential bundled tier 16 ratio reduction which would occur over 4 years and for the Super 17 Peak non-CARE minimum monthly transportation charge. As 18 discussed at the Prehearing Conference and in the November 29, 19 2017 Proposal of Pacific Gas and Electric Company for Model in 20 Response to the Request of The Administrative Law Judges at 21 The November 20, 2017 Prehearing Conference, the timing of the 22 implementation of PG&E’s proposed change to the baseline 23 season structure depends on whether there is an interim decision 24 approving such a change in approximately February 2018. The 25 baseline change is still expected to be implemented within the first 26 year after the final decision is issued, but may not be 27 implemented in time for the first winter season. PG&E also 28 intends to implement the Super Peak minimum monthly 29 transportation charge within the first year after a decision 30 approving it but not with the initial GCAP rate changes as it also 31 requires structural changes by PG&E’s billing system. 32 33

344


345 PG&E GCAP Testimony, p.1-6.

346 PG&E Response to data request ORA-09, Q.1c.

100

Since there was no interim decision on the baseline season structure 1

change in February 2018, PG&E’s proposal, if adopted as proposed, may not be 2

implemented in time for the first winter season, but as explained in the above 3

response, PG&E still expects to be able to implement it within the first year after 4

the final decision is issued. 5

8. ORA Recommendation on Future GCAPs 6

PG&E proposes that future GCAPs be filed no sooner than three years 7

from the date of PG&E’s last application filing, and no later than five years after 8

the previous application was filed.347 PG&E should provide notice to the 9

Commission whether it anticipates a delay, or is otherwise on track to file its 10

next GCAP, at least six (6) months before the planned GCAP filing. With this 11

notice, ORA does not oppose PG&E’s proposal on the filing of future GCAPs.12

347


ATTACHMENTS

ORA Attachment A

PG&E Residential Bundled Gas Commodity Procurement Charge

1

Source: PG&E website Tariff postings.

$-

$0.2000

$0.4000

$0.6000

$0.8000

$1.0000

$1.2000

$1.4000

$1.6000

$1.8000

PG&E Residential Bundled

Gas Commodity Procurement Charge $/th)

Jan 2005-Dec 2017

ORA Attachment B

PG&E Gas Transportation Rates 2005 - 2017

2

Source: PG&E Website Tariff Postings.

$0.00000

$0.20000

$0.40000

$0.60000

$0.80000

$1.00000

$1.20000

$1.40000

$1.60000

$1.800001 6

11

16

21

26

31

36

41

46

51

56

61

66

71

76

81

86

91

96

10

1

10

6

11

1

11

6

12

1

12

6

13

1

13

6

14

1

14

6

15

1

15

6

PG&E Gas Transportation Rates 2005 - 2017

in $/therm

Baseline Rate In Excess of Baseline

ORA Attachment C

COMPARISON OF ALLOCATION OF GAS DISTRIBUTION REVENUE REQUIREMENT

2

RO

WM

C: N

CO

ME

TH

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Whole

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1 C

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$374,4

76

$263,0

76

$106,0

47

$940

$476

$3,3

52

$99

$486

$0

2+

Dis

trib

utio

n422,3

50

$293,3

58

$93,9

26

$4,7

43

$2,1

48

$20,9

43

$5,9

77

$1,0

58

$198

3=

Tota

ls$796,8

27

$556,4

34

$199,9

73

$5,6

83

$2,6

24

$0

$24,2

95

$6,0

75

$1,5

44

$198

4M

CR

Scalin

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Cost fo

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7 C

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$822,8

81

$578,0

89

$233,0

31

$2,0

66

$1,0

46

$0

$7,3

65

$217

$1,0

68

$0

8+

Dis

trib

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n928,0

81

644,6

30

206,3

94

10,4

21

4,7

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046,0

21

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2,3

26

435

9+

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3,8

32

00

00

10

= T

ota

l befo

re F

&U

1,7

54,7

94

1,2

22,7

19

439,4

25

12,4

87

5,7

66

3,8

32

53,3

86

13,3

50

3,3

93

435

11

+ F

ranchis

e F

ees

24,6

92

17,2

05

6,1

83

176

81

54

751

188

48

6

12

+ U

ncolle

ctib

le R

eve

nues

5,9

76

4,1

65

1,4

97

43

20

13

182

45

12

0

13

= T

ota

l Dis

trib

utio

n B

ase R

eve

nue

$1,7

85,4

63

$1,2

44,0

90

$447,1

05

$12,7

05

$5,8

67

$3,8

99

$54,3

19

$13,5

83

$3,4

53

$441

14

Allo

catio

n %

by

Cla

ss

100.0

%69.7

%25.0

%0.7

%0.3

%0.2

%3.0

%0.8

%0.2

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%

15

MC

: R

EN

TA

L M

ET

HO

DR

esid

entia

lS

mall

Larg

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ore

Com

pre

ssio

nIn

dustr

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ctr

icT

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om

merc

ial

Com

merc

ial

NG

VC

ost fo

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-NG

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trib

utio

nT

ransm

issio

nG

en

Whole

sale

17

C

usto

mer

$998,6

11

$778,6

44

$207,4

13

$2,6

10

$537

$8,3

11

$245

$851

$0

18

+ D

istr

ibutio

n422,3

50

$293,3

58

$93,9

26

$4,7

43

$2,1

48

$20,9

43

$5,9

77

$1,0

58

$198

19

= T

ota

ls$1,4

20,9

61

$1,0

72,0

02

$301,3

39

$7,3

53

$2,6

85

$0

$29,2

54

$6,2

22

$1,9

09

$198

20

MC

R S

calin

g F

acto

r1.2

6S

calin

g to C

usto

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and

Dis

trib

utio

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unctio

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xclu

din

g G

-NG

V2 C

om

pre

ssio

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os

t and F

ranch

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ees a

nd

Uncolle

ctib

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21

Resid

entia

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Ele

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TO

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LC

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merc

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Dis

trib

utio

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Cost fo

r G

-NG

V2

Dis

trib

utio

nT

ransm

issio

nG

en

Whole

sale

23

C

usto

mer

$1,2

30,5

26

$959,4

75

$255,5

82

$3,2

17

$662

$0

$10,2

41

$302

$1,0

48

$0

24

+ D

istr

ibutio

n520,4

36

361,4

86

115,7

39

5,8

44

2,6

47

025,8

07

7,3

65

1,3

04

244

25

+ G

-NG

V2 C

om

pre

ssio

n C

ost

3,8

32

00

00

3,8

32

00

00

26

= T

ota

l befo

re F

&U

1,7

54,7

94

1,3

20,9

61

371,3

21

9,0

60

3,3

08

3,8

32

36,0

48

7,6

66

2,3

52

244

27

+ F

ranchis

e F

ees

24,6

92

18,5

88

5,2

25

127

47

54

507

108

33

3

28

+ U

ncolle

ctib

le R

eve

nues

5,9

76

4,5

00

1,2

65

31

11

13

123

26

80

29

= T

ota

l Dis

trib

utio

n B

ase R

eve

nue

$1,7

85,4

63

$1,3

44,0

48

$377,8

11

$9,2

19

$3,3

66

$3,8

99

$36,6

79

$7,8

00

$2,3

93

$248

30

Allo

catio

n %

by

Cla

ss

100.0

%75.3

%21.2

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%

Att

ach

men

t C

: F

eb

ruary

16,

2018 E

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eq

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en

t

NC

O M

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Me

tho

d,

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nta

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Me

tho

d,

Pro

po

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Em

be

dd

ed

Co

st M

eth

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nd

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rre

nt

Ad

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ttle

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nt

aft

er

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orp

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f G

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merc

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Cost fo

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trib

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nT

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en

Whole

sale

33

C

usto

mer

$1,0

38,0

69

$873,8

00

$152,2

62

$1,5

64

$1,0

74

$0

$6,7

44

$909

$1,7

16

$0

34

+ D

istr

ibutio

n719,9

64

499,3

89

159,8

92

9,0

61

3,6

56

035,6

52

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74

1,8

02

337

35

+ G

-NG

V2 C

om

pre

ssio

n C

ost

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62

00

00

3,8

62

00

00

36

= T

ota

l befo

re F

&U

1,7

61,8

96

1,3

73,1

89

312,1

54

10,6

26

4,7

30

3,8

62

42,3

97

11,0

83

3,5

18

337

37

+ F

ranchis

e F

ees

17,5

12

13,6

49

3,1

03

106

47

38

421

110

35

338

+ U

ncolle

ctib

le R

eve

nues

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55

4,7

20

1,0

73

37

16

13

146

38

12

0

39

= T

ota

l Dis

trib

utio

n B

ase R

eve

nue

$1,7

85,4

63

$1,3

91,5

58

$316,3

29

$10,7

68

$4,7

93

$3,9

14

$42,9

64

$11,2

31

$3,5

65

$341

40

Allo

catio

n %

by

Cla

ss

100.0

%77.9

%17.7

%0.6

%0.3

%0.2

%2.4

%0.6

%0.2

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%

41

CU

RR

EN

TL

Y A

DO

PT

ED

BA

SE

D O

N B

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CK

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TL

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EN

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UR

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CA

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Resid

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Sm

all

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ial

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om

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merc

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en

Whole

sale

44

C

usto

mer

$960,9

08

$838,3

65

$111,7

24

$2,3

90

$97

$0

$5,9

15

$336

$2,0

80

$0

45

+ D

istr

ibutio

n797,9

67

556,5

11

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7,9

08

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42

034,0

73

12,9

24

5,7

22

282

46

+ G

-NG

V2 C

om

pre

ssio

n C

ost

3,0

20

00

00

3,0

20

00

00

47

= T

ota

l befo

re F

&U

1,7

61,8

96

1,3

94,8

76

290,9

30

10,2

98

1,4

39

3,0

20

39,9

89

13,2

60

7,8

02

282

48

+ F

ranchis

e F

ees

17,5

12

13,8

64

2,8

92

102

14

30

397

132

78

3

49

+ U

ncolle

ctib

le R

eve

nues

6,0

55

4,7

94

1,0

00

35

510

137

46

27

0

50

= T

ota

l Dis

trib

utio

n B

ase R

eve

nue

$1,7

85,4

63

$1,4

13,5

35

$294,8

21

$10,4

36

$1,4

58

$3,0

61

$40,5

24

$13,4

37

$7,9

07

$285

51

RE

SS

ml C

om

mLrg

Com

mN

GV

NG

V C

om

pre

ssio

nIN

D-D

IND

-TE

GW

hole

sale

52

2010 B

CA

P S

ET

TLE

ME

NT

100.0

%79.2

%16.5

%0.6

%0.1

%0.2

%2.3

%0.8

%0.4

%0.0

16%

53

EM

BE

DD

ED

CO

ST

100.0

%77.9

%17.7

%0.6

%0.3

%0.2

%2.4

%0.6

%0.2

%0.0

19%

54

RE

NT

AL

100.0

%75.3

%21.2

%0.5

%0.2

%0.2

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%0.1

%0.0

14%

55

NC

O100.0

%69.7

%25.0

%0.7

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%3.0

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%0.2

%0.0

25%

4

OR

A A

TT

AC

HM

EN

T C

OR

A R

eco

mm

en

da

tio

n:

Ma

rgin

al

Co

st D

TIM

-ba

sed

MD

CC

an

d M

CA

C N

CO

Ad

just

ed

M

CR

Sca

lin

g F

act

or

0.8

60

41

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lin

g t

o C

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an

d D

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n F

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ctio

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mp

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ion

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st a

nd

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ise

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es

an

d U

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lle

ctib

les

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pe

nse

Ba

se R

eve

nu

es

(Sca

led

Ma

rgin

al C

ost

Re

ven

ue

s, in

$0

00

)

Lin

e

No

.

T

ota

l R

esi

de

nti

al

Sm

all

Co

m’l

La

rge

Co

m’l

U

nco

mp

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(C

ore

NG

V)

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NG

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ust

ria

l

Dis

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l

Tra

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Ele

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Ge

n

To

tal

Wh

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me

r $

32

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$

24

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$9

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$5

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9

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$3

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0

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Dis

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9

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5

$4

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5

$1,0

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$5

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$1

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tal D

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se R

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4

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1

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80

8

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cati

on

By

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ss %

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0%

7

5.0

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%

17

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7%

0

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0%

0

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7%

0

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9%

4

.19

4%

1

.16

0%

0

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2%

0

.03

8%

9

OR

A R

ep

rod

uct

ion

Re

sult

s o

f P

G&

E A

tta

chm

en

t C

: Fe

bru

ary

16

, 2

01

8 E

rra

ta a

t Li

ne

s 1

08

- 1

11

10

2

01

0 B

CA

P

Se

ttle

me

nt

10

0%

7

9.2

%

16

.5%

0

.6%

0

.1%

0

.2%

2

.3%

0

.8%

0

.4%

0

.01

6%

11

E

mb

ed

de

d C

ost

1

00

%

77

.9%

1

7.7

%

0.6

%

0.3

%

0.2

%

2.4

%

0.6

%

0.2

%

0.0

19

%

12

R

en

tal

10

0%

7

5.3

%

21

.2%

0

.5%

0

.2%

0

.2%

2

.1%

0

.4%

0

.1%

0

.01

4%

13

NC

O

10

0%

6

9.7

%

25

.0%

0

.7%

0

.3%

0

.2%

3

.0%

0

.8%

0

.2%

0

.02

5%

ORA ATTACHMENT D

2018 GCAP ENHANCED TOOL RUNS

1

6

ORA ATTACHMENT D

ORA MC & PG&E GCAP PROPOSALS Except TIER RATIO

BILL IMPACT DASHBOARD RESULTS AT SCENARIO SETTINGS

BELOW:

1. AT 10 FOR ALLOCATION OF GAS BASE DISTRIBUTION REVENUE

REQUIREMENT348 (ORA’S MC DTIM-BASED MDCC & MCAC NCO Adjusted basis)

2. AT 2 FOR ALLOCATION OF ENERGY EFFICIENCY-RELATED PORTIONS OF GAS

PPP SURCHARGE

3. AT 1 FOR PG&E RESIDENTIAL BASELINE ALLOWANCE SEASON STRUCTURE

(PG&E 3 MONTHS, 9-MO. NON-PEAK)

4. AT $15 FOR MINIMUM MONTHLY NON-CARE RESIDENTIAL TRANSPORTATION

CHARGE – BASIC SERVICE (PG&E)

5. AT $45 FOR MINIMUM MONTHLY NON-CARE RESIDENTIAL TRANSPORTATION

CHARGE – SUPER PEAK SERVICE (PG&E)

6. AT 1.41 FOR RESIDENTIAL BUNDLED TIER RATIO FOR ALL 4 YEARS (NO

CHANGES TO CURRENT STATUS OF TIER RATIO)

7. AT 1 FOR USE OF OCT 2016-SEPT 2017 ACTUAL RECORDED GAS USAGE

8. AT 1 FOR COST OF GAS TO CALCULATE RESIDENTIAL CORE PROCUREMENT

RATE APPLICABLE TO BUNDLED CUSTOMER BILL CALCULATIONS

Note: ORA’s Recommendation on Baseline Season Structure is not appropriately reflected in

Scenario Settings. Refer to Section III.B of Ex. ORA-05.

348

Subsequently changed to Scenario “10.”

7

1

Sou

rce

: P

G&

E 2

01

8 G

CA

P E

nh

an

ced

To

ol,

Ta

b “

Sce

na

rio

Sett

ing

s”

2

8

1

61

23

45

67

89

10

Scenario

Chosen in

Sw

itches

PG

&E

Pro

posed-

Em

bedded

(Feb 1

5, 2018

Err

ata

)

PG

&E

File

d-

Marg

inal w

/NC

O

(Feb. 15, 2018

Err

ata

)

PG

&E

File

d -

Marg

inal w

/Renta

l

(Feb. 15, 2018

Err

ata

)

PG

&E

Em

bedded

Cost (E

rrata

)

Isola

ted C

hange to

Pre

sent R

ate

s

w/2

010 B

CA

P

Thro

ughput

PG

&E

July

2017

SG

IP

GR

C

(Sta

tus

Quo)

Av

ailab

le

for

Use

r

Sce

nari

o

Av

ailab

le

for

Use

r

Sce

nari

o

Av

ailab

le

for

Use

r

Sce

nari

o

Av

ailab

le

for

Use

r

Sce

nari

o

Liv

e L

ink

to R

D

Mo

de

l

RE

SID

EN

TIA

L N

ON

-CA

RE

RA

TE

S(P

rese

nt

Rate

s)

Resulti

ng N

on-C

AR

E A

vera

ge D

istr

ibutio

n R

ate

($/th)

$.6

62

$.7

4260

$.6

6453

$.7

1804

$.6

9004

0.7

02861

0.6

6198

$.7

4260

Gas B

ase D

istr

ibutio

n R

RQ

: %

of C

ore

Allo

cate

d to R

es

73.6

%80.5

60%

72.6

37%

77.3

63%

80.3

54%

82.0

2%

0.7

36099

80.5

60%

Bal A

cct. B

al (

$000)

Allo

cate

d U

sin

g B

ase D

istr

ibutio

n A

lloc %

$297,9

10

Allo

catio

n to R

esid

entia

l Cla

ss

$219,2

91

Resid

entia

l Volu

mes

1,8

73,9

00

Resulti

ng R

es R

ate

($/th)

$0.1

17

Add P

ort

ion n

ot A

llocate

d u

sin

g B

ase D

istr

ibutio

n A

llocatio

n$0.0

25

Year

1C

CC

+ S

tate

Fee C

om

ponent fo

r S

cenario C

hosen

$.1

4220

Gas B

ase D

istr

ibutio

n R

RQ

: %

of C

ore

Allo

cate

d to R

es

73.6

%

Bal A

cct. B

al (

$000)

Allo

cate

d U

sin

g B

ase D

istr

ibutio

n A

lloc %

$207,9

10

Allo

catio

n to R

esid

entia

l Cla

ss

$153,0

42

Resid

entia

l Volu

mes

1,8

73,9

00

Resulti

ng R

es R

ate

($/th)

$0.0

82

Add P

ort

ion n

ot A

llocate

d u

sin

g B

ase D

istr

ibutio

n A

llocatio

n$0.0

25

Year

2C

CC

+ S

tate

Fee C

om

ponent fo

r S

cenario C

hosen

$.1

0685

Gas B

ase D

istr

ibutio

n R

RQ

: %

of C

ore

Allo

cate

d to R

es

73.6

%

Bal A

cct. B

al (

$000)

Allo

cate

d U

sin

g B

ase D

istr

ibutio

n A

lloc %

$207,9

10

Allo

catio

n to R

esid

entia

l Cla

ss

$153,0

42

Resid

entia

l Volu

mes

1,8

73,9

00

Resulti

ng R

es R

ate

($/th)

$0.0

82

Add P

ort

ion n

ot A

llocate

d u

sin

g B

ase D

istr

ibutio

n A

llocatio

n$0.0

25

Year

3C

CC

+ S

tate

Fee C

om

ponent fo

r S

cenario C

hosen

$.1

0685

Gas B

ase D

istr

ibutio

n R

RQ

: %

of C

ore

Allo

cate

d to R

es

73.6

%

Bal A

cct. B

al (

$000)

Allo

cate

d U

sin

g B

ase D

istr

ibutio

n A

lloc %

$207,9

10

Allo

catio

n to R

esid

entia

l Cla

ss

$153,0

42

Resid

entia

l Volu

mes

1,8

73,9

00

Resulti

ng R

es R

ate

($/th)

$0.0

82

Add P

ort

ion n

ot A

llocate

d u

sin

g B

ase D

istr

ibutio

n A

llocatio

n$0.0

25

Year

4C

CC

+ S

tate

Fee C

om

ponent fo

r S

cenario C

hosen

$.1

0685

Pur

po

se: A

dju

st c

usto

me

r cla

ss c

harg

e c

om

po

nents

of re

sid

entia

l ra

tes fo

r sc

ena

rio

se

lectio

n o

f

ga

s b

ase

dis

trib

utio

n r

eve

nue

re

quir

em

ent a

lloca

tion.

Sc

en

ari

o i

s c

ho

se

n i

n S

ce

na

rio

Se

ttin

gs t

ab

.

9

1

2

Sce

na

rio

Se

ttin

gs:

Co

ntr

ol

Pa

ne

l

Sc

en

ari

oE

xp

lan

ati

on

of

Sc

en

ari

oS

ce

na

rio

Se

ttin

g O

pti

on

sP

G&

E's

GC

AP

20

18

Pro

po

sa

l S

ce

nari

o

Se

ttin

g Y

ear

1

Sce

nari

o

Se

ttin

g Y

ear

2

Sce

nari

o

Se

ttin

g Y

ear

3

Sce

nari

o

Se

ttin

g Y

ear

4

Allo

catio

n o

f G

as B

ase

Dis

trib

utio

n R

eve

nue

Re

quire

me

nt

Em

bed

de

d v

ers

us M

arg

inal C

ost f

or

GR

C P

hase I

Gas D

istrib

ution R

RQ

Allo

cation A

cross C

ust

om

er

Cla

sses

1 = E

mbe

dde

d C

ost w

/Upd

ate

d T

hro

ug

hput

2 = M

arg

inal C

ost - N

CO

w/U

pdate

d T

hro

ughput

3 = M

arg

inal C

ost - R

enta

l w/U

pda

ted T

hroughput

4 =

20

10

Ad

opte

d S

ettle

me

nt w

/Em

be

dd

ed C

ost

iso

late

d c

hange

5 =

PG

&E

Jul

y 2

017

SG

IP G

RC

(20

10

BC

AP

Ad

op

ted M

CR

Se

ttlem

ent

)

6 =

7 =

8 =

9 =

10 =

Curr

ent 201

8 G

CA

P R

D M

od

el S

cenario

1

Allo

catio

n o

f E

ne

rgy

Eff

icie

ncy-

rela

ted

po

rtio

ns o

f

the

Gas P

PP

Surc

harg

e

Allo

cation o

f E

nerg

y E

ffic

ienc

y po

rtio

n

of th

e G

as P

PP

Surc

harg

e

0 = S

tatu

s Q

uo A

llocation (1

996

Stu

dy)

& R

ate

s

1 =

S

tatu

s Q

uo A

llocation (1

996

Stu

dy)

w/T

hroughp

ut

Up

da

te

2 = U

pd

ate

d S

tudy

w/T

hro

ughp

ut U

pd

ate

3 =

Upd

ate

d S

tudy

w/ C

urr

ent 201

4-2

016 R

eco

rde

d

Thro

ughp

ut

2

Re

sid

entia

l Base

line

Allo

wance

Se

aso

n S

tructu

re0 = S

tatu

s Q

uo

: 5 M

onth

Win

ter;

7 M

onth

Sum

me

r;

Allo

wances U

pda

ted in P

G&

E's

20

17

GR

C P

h II

1 = 20

18 G

CA

P P

G&

E P

rop

osal:

3 M

ont

h P

eak

Win

ter; 9

Month

Non-P

eak; A

llow

ances C

alc

ula

ted

Usin

g S

am

e H

isto

ric

Peri

od a

s 2

017

GR

C P

h II

11

11

1

Min

imum

Mo

nth

ly N

on-C

AR

E R

esid

entia

l

Tra

nsp

ort

atio

n C

harg

e -

Basic

Se

rvic

e

Curr

ent V

alu

e s

ince 2

005

is $

3 o

nly

app

lica

ble

to n

on-

CA

RE

ind

ivid

ually

mete

red

custo

me

rs

Ente

r A

ny V

alu

e o

f $3 o

r m

ore

($3 is

the c

urre

nt a

dop

ted a

mount)

$15 for

Non-C

AR

E R

esid

ent

ial C

ust

om

ers

$4.0

0$4.0

0$4.0

0$4.0

0

Min

imum

Mo

nth

ly N

on-C

AR

E R

esid

entia

l

Tra

nsp

ort

atio

n C

harg

e -

Sup

er

Pe

ak

Se

rvic

e

Min

imum

Mo

nthly

non-C

AR

E

Tra

nsp

orta

tion c

harg

e fo

r S

uper

Peak

serv

ice is

now

the s

am

e $

3 a

pplic

ab

le

to B

asic

Serv

ice

cust

om

ers

Ente

r A

ny V

alu

e o

f $0 o

r m

ore

($0 is

the c

urre

nt a

dop

ted m

eth

od)

$45 for

Non-C

AR

E R

esid

ent

ial C

ust

om

ers

with

Pea

k D

aily

Gas U

sag

e D

uri

ng P

ast

11

Mo

nths a

nd C

urr

ent

Bill

ing

peri

od

of a

t le

ast

15 the

rms

$12.0

0$12.0

0$12.0

0$12.0

0

Re

sid

entia

l Bund

led

Rate

Tie

r R

atio

(Tie

r 2

/Tie

r1)

Ente

r de

sire

d s

cenario

ra

tios;

Run

Macro

whe

n all

setti

ngs e

nte

red to

calc

ula

te re

sulti

ng ra

tes

Ente

r D

esi

red

Re

sid

entia

l Bundle

d R

ate

Tie

r R

atio

.

Sta

tus Q

uo c

urr

ent e

ffectiv

e ratio is 1

.40

5 for

all

four

years

.

PG

&E

pro

poses to the

follo

win

g p

hase

in

tier

ratio

: 1.3

5, 1.3

0, 1.2

5, 1

.20.

1.3

51.3

01.2

51.2

0

Use

Oct 2

01

6-S

ep

t 2

01

7 A

ctu

al R

eco

rde

d U

sag

e

by

Custo

me

r o

r T

em

pe

ratu

re N

orm

aliz

ed

Usag

e

(the

rms/c

usto

me

r/m

onth

)

Usag

e B

asis

for C

alc

ulating

Month

ly

Bill

s by

Base

line

Terr

itory

and for

Tota

l

Sys

tem

0 = R

ecord

ed

Usa

ge p

er C

ust

om

er

(10

/201

6 -

9/2

017)

1 =

Te

mpe

ratu

re A

dju

ste

d U

sage

pe

r C

usto

me

r

(based o

n 1

0/2

016-9

/2017

)

2 =

Record

ed U

sage

per

Custo

mer

(10/2

009

-9/2

01

0)

No

t Ap

plic

ab

le

Co

st o

f G

as U

se

d to

Calc

ula

te R

esid

entia

l Co

re

Pro

cure

me

nt R

ate

ap

plic

ab

le to

Bund

led

Custo

me

r B

ill C

alc

ula

tions

Allo

ws T

oo

l Users

to u

se a

ctual

month

ly c

ost of ga

s d

urin

g th

e s

am

e

peri

od

from

whic

h the

custo

mer

usa

ge

refe

renc

es o

r th

e a

nnu

al a

vera

ge

co

st

of gas u

nderlyi

ng rate

s file

d in

PG

&E

's

201

8 G

CA

P a

pp

lica

tion

0 = A

ctual C

ost o

f G

as b

y M

onth

for

10/2

016

- 9

/2017

peri

od

1 = A

nnual A

vera

ge C

ost

of G

as in

PG

&E

's 2

01

7 J

uly

Tra

nsp

ort

ation R

ate

Change

2 = R

ecalc

ula

te 2

01

7 A

nnual A

vera

ge C

ost

of G

as fo

r

Impa

cts o

f Thro

ughput o

n n

on-c

om

mo

dity

allo

catio

n

1

Purp

ose

: P

rovi

de

s u

se

r ab

ility

to

pic

k d

iffe

rent co

mb

inatio

ns o

f p

olic

y p

rop

osals

be

twe

en G

CA

P a

nd

curr

ent ra

tes a

nd

bill

s. T

he

use

r can a

lso

co

me

up

with

the

ir o

wn p

rop

osal.

The

orig

inal s

ettin

gs in

co

lum

ns E

thro

ug

h H

are

se

t to

pro

duce

no

chang

e in

rate

s f

rom

pre

se

nt (J

uly

20

17

) and

the

use

r can b

eg

in to

exp

lore

sce

nario

s b

oth

in c

om

bin

atio

n a

nd

iso

latio

n.

1110 2

Pre

ss t

o R

un

Rate

an

d B

ill S

cen

ari

o

To

se

e r

esu

lts

of

the

cu

rre

nt

run

in t

he

fo

rma

t b

elo

w,

Go

to T

ota

lPro

po

sed

Bill

s ta

b

-M

on

thly

bill

s o

ve

r fo

ur

ye

ars

acr

oss

ta

b-

Re

sid

en

tia

l cu

sto

me

r se

gm

en

ted

as

follo

ws

do

wn

ta

b

-B

y n

on

-CA

RE

vs

CA

RE

cu

sto

me

rs

-B

y B

un

dle

dv

s T

ran

spo

rt o

nly

cu

sto

me

rs

-B

y b

ase

line

te

rrit

ory

-B

y 2

5th

, 50

th, a

nd

75

th p

erc

en

tile

usa

ge

lev

el

Pre

ss B

utt

on

Be

low

to

Ite

rate

Ra

tes

an

d C

alc

ula

te B

ills

Aft

er

Ch

an

gin

g

Po

licy

Ch

oic

es

10

1

10

12

34

56

78

910

Scenario

Chosen in

Sw

itches

PG

&E

Pro

posed-

Em

bedded

(Feb 1

5, 2018

Err

ata

)

PG

&E

File

d-

Marg

inal w

/NC

O

(Feb. 15, 2018

Err

ata

)

PG

&E

File

d -

Marg

inal w

/Renta

l

(Feb. 15, 2018

Err

ata

)

PG

&E

Em

bedded

Cost (E

rrata

)

Isola

ted C

hange to

Pre

sent R

ate

s

w/2

010 B

CA

P

Thro

ughput

PG

&E

July

2017

SG

IP

GR

C

(Sta

tus

Quo)

Av

ailab

le

for

Use

r

Sce

nari

o

Av

ailab

le

for

Use

r

Sce

nari

o

Av

ailab

le

for

Use

r

Sce

nari

o

Av

ailab

le

for

Use

r

Sce

nari

o

Liv

e L

ink

to R

D

Mo

de

l

RE

SID

EN

TIA

L N

ON

-CA

RE

RA

TE

S(P

rese

nt

Rate

s)

Resulti

ng N

on-C

AR

E A

vera

ge D

istr

ibutio

n R

ate

($/th)

$.6

62

$.7

4260

$.6

6453

$.7

1804

$.6

9004

0.7

02861

0.6

6198

$.6

6198

Gas B

ase D

istr

ibutio

n R

RQ

: %

of C

ore

Allo

cate

d to R

es

73.6

%80.5

60%

72.6

37%

77.3

63%

80.3

54%

82.0

2%

0.7

36099

73.6

10%

Bal A

cct. B

al (

$000)

Allo

cate

d U

sin

g B

ase D

istr

ibutio

n A

lloc %

$297,9

10

Allo

catio

n to R

esid

entia

l Cla

ss

$219,2

91

Resid

entia

l Volu

mes

1,8

73,9

00

Resulti

ng R

es R

ate

($/th)

$0.1

17

Add P

ort

ion n

ot A

llocate

d u

sin

g B

ase D

istr

ibutio

n A

llocatio

n$0.0

25

Year

1C

CC

+ S

tate

Fee C

om

ponent fo

r S

cenario C

hosen

$.1

4195

Gas B

ase D

istr

ibutio

n R

RQ

: %

of C

ore

Allo

cate

d to R

es

73.6

%

Bal A

cct. B

al (

$000)

Allo

cate

d U

sin

g B

ase D

istr

ibutio

n A

lloc %

$207,9

10

Allo

catio

n to R

esid

entia

l Cla

ss

$153,0

42

Resid

entia

l Volu

mes

1,8

73,9

00

Resulti

ng R

es R

ate

($/th)

$0.0

82

Add P

ort

ion n

ot A

llocate

d u

sin

g B

ase D

istr

ibutio

n A

llocatio

n$0.0

25

Year

2C

CC

+ S

tate

Fee C

om

ponent fo

r S

cenario C

hosen

$.1

0659

Gas B

ase D

istr

ibutio

n R

RQ

: %

of C

ore

Allo

cate

d to R

es

73.6

%

Bal A

cct. B

al (

$000)

Allo

cate

d U

sin

g B

ase D

istr

ibutio

n A

lloc %

$207,9

10

Allo

catio

n to R

esid

entia

l Cla

ss

$153,0

42

Resid

entia

l Volu

mes

1,8

73,9

00

Resulti

ng R

es R

ate

($/th)

$0.0

82

Add P

ort

ion n

ot A

llocate

d u

sin

g B

ase D

istr

ibutio

n A

llocatio

n$0.0

25

Year

3C

CC

+ S

tate

Fee C

om

ponent fo

r S

cenario C

hosen

$.1

0659

Gas B

ase D

istr

ibutio

n R

RQ

: %

of C

ore

Allo

cate

d to R

es

73.6

%

Bal A

cct. B

al (

$000)

Allo

cate

d U

sin

g B

ase D

istr

ibutio

n A

lloc %

$207,9

10

Allo

catio

n to R

esid

entia

l Cla

ss

$153,0

42

Resid

entia

l Volu

mes

1,8

73,9

00

Resulti

ng R

es R

ate

($/th)

$0.0

82

Add P

ort

ion n

ot A

llocate

d u

sin

g B

ase D

istr

ibutio

n A

llocatio

n$0.0

25

Year

4C

CC

+ S

tate

Fee C

om

ponent fo

r S

cenario C

hosen

$.1

0659

Pur

po

se: A

dju

st c

usto

me

r cla

ss c

harg

e c

om

po

nents

of re

sid

entia

l ra

tes fo

r sc

ena

rio

se

lectio

n o

f

ga

s b

ase

dis

trib

utio

n r

eve

nue

re

quir

em

ent a

lloca

tion.

Sc

en

ari

o i

s c

ho

se

n i

n S

ce

na

rio

Se

ttin

gs t

ab

.

11

1

2

OR

A M

AR

GIN

AL

CO

ST

AD

JU

ST

ED

10

12

34

56

78

910

Scenario

Chosen in

Sw

itches

PG

&E

Pro

posed-

Em

bedded

(Feb 1

5, 2018

Err

ata

)

PG

&E

File

d-

Marg

inal w

/NC

O

(Feb. 15, 2018

Err

ata

)

PG

&E

File

d -

Marg

inal w

/Renta

l

(Feb. 15, 2018

Err

ata

)

PG

&E

Em

bedded

Cost (E

rrata

)

Isola

ted C

hange to

Pre

sent R

ate

s

w/2

010 B

CA

P

Thro

ughput

PG

&E

July

2017

SG

IP

GR

C

(Sta

tus

Quo)

Av

ailab

le

for

Use

r

Sce

nari

o

Av

ailab

le

for

Use

r

Sce

nari

o

Av

ailab

le

for

Use

r

Sce

nari

o

Av

ailab

le

for

Use

r

Sce

nari

o

Liv

e L

ink

to R

D

Mo

de

l

RE

SID

EN

TIA

L N

ON

-CA

RE

RA

TE

S(P

rese

nt

Rate

s)

Resulti

ng N

on-C

AR

E A

vera

ge D

istr

ibutio

n R

ate

($/th)

$.7

15

$.7

4260

$.6

6453

$.7

1804

$.6

9004

0.7

02861

0.6

6198

$.7

1490

Gas B

ase D

istr

ibutio

n R

RQ

: %

of C

ore

Allo

cate

d to R

es

79.5

%80.5

60%

72.6

37%

77.3

63%

80.3

54%

82.0

2%

0.7

36099

79.4

95%

Bal A

cct. B

al (

$000)

Allo

cate

d U

sin

g B

ase D

istr

ibutio

n A

lloc %

$297,9

10

Allo

catio

n to R

esid

entia

l Cla

ss

$236,8

23

Resid

entia

l Volu

mes

1,8

73,9

00

Resulti

ng R

es R

ate

($/th)

$0.1

26

Add P

ort

ion n

ot A

llocate

d u

sin

g B

ase D

istr

ibutio

n A

llocatio

n$0.0

25

Year

1C

CC

+ S

tate

Fee C

om

ponent fo

r S

cenario C

hosen

$.1

5143

Gas B

ase D

istr

ibutio

n R

RQ

: %

of C

ore

Allo

cate

d to R

es

79.5

%

Bal A

cct. B

al (

$000)

Allo

cate

d U

sin

g B

ase D

istr

ibutio

n A

lloc %

$207,9

10

Allo

catio

n to R

esid

entia

l Cla

ss

$165,2

78

Resid

entia

l Volu

mes

1,8

73,9

00

Resulti

ng R

es R

ate

($/th)

$0.0

88

Add P

ort

ion n

ot A

llocate

d u

sin

g B

ase D

istr

ibutio

n A

llocatio

n$0.0

25

Year

2C

CC

+ S

tate

Fee C

om

ponent fo

r S

cenario C

hosen

$.1

1325

Gas B

ase D

istr

ibutio

n R

RQ

: %

of C

ore

Allo

cate

d to R

es

79.5

%

Bal A

cct. B

al (

$000)

Allo

cate

d U

sin

g B

ase D

istr

ibutio

n A

lloc %

$207,9

10

Allo

catio

n to R

esid

entia

l Cla

ss

$165,2

78

Resid

entia

l Volu

mes

1,8

73,9

00

Resulti

ng R

es R

ate

($/th)

$0.0

88

Add P

ort

ion n

ot A

llocate

d u

sin

g B

ase D

istr

ibutio

n A

llocatio

n$0.0

25

Year

3C

CC

+ S

tate

Fee C

om

ponent fo

r S

cenario C

hosen

$.1

1325

Gas B

ase D

istr

ibutio

n R

RQ

: %

of C

ore

Allo

cate

d to R

es

79.5

%

Bal A

cct. B

al (

$000)

Allo

cate

d U

sin

g B

ase D

istr

ibutio

n A

lloc %

$207,9

10

Allo

catio

n to R

esid

entia

l Cla

ss

$165,2

78

Resid

entia

l Volu

mes

1,8

73,9

00

Resulti

ng R

es R

ate

($/th)

$0.0

88

Add P

ort

ion n

ot A

llocate

d u

sin

g B

ase D

istr

ibutio

n A

llocatio

n$0.0

25

Year

4C

CC

+ S

tate

Fee C

om

ponent fo

r S

cenario C

hosen

$.1

1325

Pur

po

se: A

dju

st c

usto

me

r cla

ss c

harg

e c

om

po

nents

of re

sid

entia

l ra

tes fo

r sc

ena

rio

se

lectio

n o

f

ga

s b

ase

dis

trib

utio

n r

eve

nue

re

quir

em

ent a

lloca

tion.

Sc

en

ari

o i

s c

ho

se

n i

n S

ce

na

rio

Se

ttin

gs t

ab

.

ORA ATTACHMENT E ORA RESULTS OF PG&E GCAP ENHANCED TOOL RUNS

WORKPAPERS FROM PG&E GCAP ENHANCED TOOL

BILL IMPACT DASHBOARD TABLES

7

ORA MC & PG&E GCAP PROPOSALS Except TIER RATIO 1

2

BILL IMPACT DASHBOARD RESULTS AT SCENARIO SETTINGS 3

BELOW: 4

1. AT 10 FOR ALLOCATION OF GAS BASE DISTRIBUTION REVENUE 5 REQUIREMENT (ORA’S MC DTIM-BASED MDCC & MCAC NCO Adjusted) 6

7

2. AT 2 FOR ALLOCATION OF ENERGY EFFICIENCY-RELATED PORTIONS OF 8 GAS PPP SURCHARGE 9

10

3. AT 1 FOR PG&E RESIDENTIAL BASELINE ALLOWANCE SEASON STRUCTURE 11 (PG&E 3 MONTHS, 9-MO. NON-PEAK) 12

13

4. AT $15 FOR MINIMUM MONTHLY NON-CARE RESIDENTIAL TRANSPORTATION 14 CHARGE – BASIC SERVICE (PG&E) 15

16

5. AT $45 FOR MINIMUM MONTHLY NON-CARE RESIDENTIAL TRANSPORTATION 17 CHARGE – SUPER PEAK SERVICE (PG&E) 18

19

6. AT 1.41 FOR RESIDENTIAL BUNDLED TIER RATIO FOR ALL 4 YEARS (NO 20 CHANGES TO CURRENT STATUS OF TIER RATIO) 21

22

7. AT 1 FOR USE OF OCT 2016-SEPT 2017 ACTUAL RECORDED GAS USAGE 23

24

8. AT 1 FOR COST OF GAS TO CALCULATE RESIDENTIAL CORE PROCUREMENT 25 RATE APPLICABLE TO BUNDLED CUSTOMER BILL CALCULATIONS 26

27 Note: ORA’s Recommendation on Baseline Season Structure is not appropriately reflected in 28 Scenario Settings. Refer to Section III.B of Ex. ORA-0529

10

1 ORA

25th Percentile

CARE Bundled

System Average

Territory S (Central

Valley) Territory T (Coast)

Territory X (Inner

Valley)

Present Average Monthly Bill $23.99 $19.18 $19.40

Proposed Yr1 Average Monthly

Bill $21.87 $17.37 $18.24


Bill $21.30 $16.91 $17.10


Bill $21.30 $16.91 $17.10


Bill $21.30 $16.91 $17.10

Compound Annual % Change

-2.9% -3.1% -3.1%

Source: Excel Range Rows S38 through W44, Tab Bill Impact Dashboard

2 ORA

25th Percentile

Non-CARE

Bundled System

Average



Territory X (Inner

Valley)



Bill $35.10 $24.84 $33.12


Bill $34.61 $24.63 $32.59


Bill $34.61 $24.63 $32.59


Bill $34.61 $24.63 $32.59


0.0% -0.1% -0.7%

Source: Excel Range Rows C38 through G44, Tab Bill Impact Dashboard

3 ORA

25th Percentile

Non-CARE

Bundled System

Average

(estimated)



Territory X (Inner

Valley)

Present Winter Bill Volatility

(Std. Dev.) 25.2% 29.3% 14.5% 24.1%

Proposed Winter Bill Volatility

(Std. Dev.) Yr1 21.4% 22.5% 14.5% 20.4%


(Std. Dev.) Yr2 21.1% 22.1% 13.6% 20.3%


(Std. Dev.) Yr3 21.1% 22.1% 13.6% 20.3%


(Std. Dev.) Yr4 21.1% 22.1% 13.6% 20.3%

Source: Excel Range Rows Y28 through AC33, Tab Bill Impact Dashboard.

11

4 ORA

50th Percentile

CARE Bundled

System Average

Territory S

(Central

Valley)

Territory

T (Coast)

Territory X

(Inner

Valley)


Proposed Yr1 Average Monthly Bill $34.03 $30.05 $30.59




Compound Annual % Change -3.1% -3.0% -2.9%

Source: Excel Range Row S48 through W54, Tab Bill Impact Dashboard.

5 ORA

50th Percentile

Non-CARE Bundled

System Average

Territory S

(Central

Valley)

Territory

T (Coast)

Territory X

(Inner

Valley)

Present Average Monthly Bill $51.38 $52.44 $46.35 $53.49

Proposed Yr1 Average Monthly Bill $48.49 $50.48 $42.52 $50.38





Source: Excel Range Row C48 through G54, Tab Bill Impact Dashboard.

6 ORA

Std Dev. as % of Avg. Bill

50th

Percentile

Non-CARE

Bundled

System

Average

Territory S

(Central

Valley)

Territory

T (Coast)

Territory X

(Inner

Valley)

Present Winter Bill Volatility (Std. Dev.) 29.7% 35.1% 21.2% 28.3%

Proposed Winter Bill Volatility (Std.

Dev.) Yr1 21.5% 25.9% 14.7% 20.5%


Dev.) Yr2 21.3% 25.6% 14.7% 20.5%


Dev.) Yr3 21.3% 25.6% 14.7% 20.5%


Dev.) Yr4 21.3% 25.6% 14.7% 20.5%


12

7 ORA

50th Percentile

Non-CARE

Bundled System

Average

Territory S

(Central Valley)

Territory T

(Coast)

Territory X

(Inner Valley)

Present November to December Bill

Differentials $53.61 $67.80 $31.33 $53.25

Proposed November to December Bill

Differentials Yr1 $32.83 $42.77 $18.30 $32.23







Source: Excel Range Row I28 through M33, Tab Bill Impact Dashboard.

8 ORA

75th Percentile

CARE Bundled

System Average



Territory X

(Inner Valley)







-2.8% -2.7% -2.8%


9 ORA

75th Percentile

Non-CARE

Bundled System

Average



Territory X

(Inner Valley)







-2.0% -2.8% -2.6%


13

10 ORA

75th Percentile

Non-CARE Bundled

System Average

(estimated)



Territory X (Inner

Valley)


(Std. Dev.) 29.0% 32.8% 22.7% 27.7%


(Std. Dev.) Yr1 22.1% 25.0% 17.3% 21.1%


(Std. Dev.) Yr2 22.0% 24.8% 17.3% 21.1%


(Std. Dev.) Yr3 22.0% 24.8% 17.3% 21.1%


(Std. Dev.) Yr4 22.0% 24.8% 17.3% 21.1%

Source: Excel Range RowS28 through W33, Tab Bill Impact Dashboard.

11 ORA

50th Non-

CARE

Bundled

System Avg

50th CARE

Bundled

System Avg

50th Territory

S (Coast) Non-

CARE

50th Territory

T (Coast) non-

CARE

CARE 25th

Percentile

Territory X

CARE 50th

Percentile

Territory X

CARE 75th

Percentile

Territory X

Present $110.47 $65.44 $124.71 $80.48 $32.06 $56.31 $96.18

Yr 1 $97.29 $57.64 $109.82 $70.60 $29.03 $50.98 $84.83

Yr 2 $94.76 $56.13 $106.96 $68.77 $28.27 $49.65 $82.59

Yr 3 $94.76 $56.13 $106.96 $68.77 $28.27 $49.65 $82.59

Yr 4 $94.76 $56.13 $106.96 $68.77 $28.27 $49.65 $82.59

Source: Excel Range RowI38 through P43, Tab Bill Impact Dashboard.

12 ORA

Compounded Annual % Change in Rates By Residential Segment

Territory S

(Central Valley)

Territory T

(Coast)

Territory X (Inner

Valley)

CAREBundled: 25th Percentile -2.9% -3.1% -3.1%



Non-CARE Bundled: 25th Percentile 0.0% -0.1% -0.7%

Non-CARE Bundled: 50th Percentile -1.4% -2.7% -2.0%



14

O

RA

MA

RG

INA

L C

OST

AD

JUST

ED

13

OR

A

Avg

Mo

. B

ills:

50

th

Pe

rce

nti

le

Oct

ob

er

No

vem

be

r D

ece

mb

er

Jan

ua

ry

Fe

bru

ary

M

arc

h

Ap

ril

Ma

y Ju

ne

Ju

ly

Au

gu

st

Se

pte

mb

er

To

tal

Pre

sen

t $

35

.33

$

61

.87

$

11

5.4

8

$1

05

.47

$

66

.46

$

57

.59

$

50

.94

$

32

.67

$

24

.35

$

21

.58

$

21

.32

$

23

.44

$

61

6.5

0

Cu

rre

nt

Pro

po

sed

Sce

na

rio

$3

1.7

8

$7

2.7

3

$1

08

.41

$

98

.69

$

64

.09

$

66

.98

$

46

.93

$

29

.19

$

22

.42

$

20

.47

$

20

.29

$

21

.77

$

60

3.7

5

No

n-C

AR

E B

un

dle

d

($3

.56

) $

10

.86

($

7.0

7)

($6

.78

) ($

2.3

7)

$9

.39

($

4.0

2)

($3

.48

) ($

1.9

3)

($1

.11

) ($

1.0

3)

($1

.66

) ($

12

.76

)

CA

RE

Bu

nd

led

($

2.9

2)

$6

.65

($

4.3

3)

($3

.96

) ($

1.5

7)

$5

.63

($

3.1

6)

($2

.85

) ($

2.4

1)

($1

.56

) ($

1.7

8)

($2

.19

) ($

14

.44

)

% C

ha

ng

e

-10

%

18

%

-6%

-6

%

-4%

1

6%

-8

%

-11

%

-8%

-5

%

-5%

-7

%

-36

%

O

cto

be

r N

ove

mb

er

De

cem

be

r Ja

nu

ary

F

eb

rua

ry

Ma

rch

A

pri

l M

ay

Jun

e

July

A

ug

ust

S

ep

tem

be

r

Te

rrit

ory

X N

on

-

CA

RE

: 2

5th

Pe

rce

nti

le C

ha

ng

e

($1

.63

) $

3.1

9

($2

.40

) ($

2.2

7)

($1

.54

) $

2.7

2

($3

.71

) ($

0.9

9)

($0

.64

) ($

0.5

9)

($0

.58

) ($

0.6

2)

($9

.06

)

Te

rrit

ory

X N

on

-

CA

RE

: 7

5th

Pe

rce

nti

le C

ha

ng

e

($4

.33

) $

15

.38

($

8.8

7)

($8

.49

) ($

6.8

2)

$1

5.7

4

($5

.17

) ($

4.2

1)

($3

.72

) ($

2.6

7)

($2

.83

) ($

3.6

8)

($1

9.6

7)

O

cto

be

r N

ove

mb

er

De

cem

be

r Ja

nu

ary

F

eb

rua

ry

Ma

rch

A

pri

l M

ay

Jun

e

July

A

ug

ust

S

ep

tem

be

r

Te

rrit

ory

X C

AR

E:

25

th P

erc

en

tile

Ch

an

ge

($0

.58

) ($

0.5

5)

($1

.25

) ($

1.1

5)

($0

.85

) ($

0.6

1)

($1

.38

) ($

0.5

9)

($0

.49

) ($

0.4

5)

($0

.44

) ($

0.4

8)

($8

.81

)

Te

rrit

ory

X C

AR

E:

75

th P

erc

en

tile

Ch

an

ge

($3

.46

) $

12

.07

($

6.0

5)

($5

.74

) ($

2.2

8)

$1

0.3

5

($3

.85

) ($

3.3

6)

($3

.07

) ($

2.6

7)

($2

.84

) ($

3.0

4)

($1

3.9

5)

So

urc

e:

Exc

el R

an

ge

Ro

w C

79

th

rou

gh

P9

0,

Ta

b B

ill I

mp

act

Da

shb

oa

rd.

ORA ATTACHMENT F

COMPARISON PG&E RESULTS

PG&E EC & PG&E GCAP PROPOSALS Except TIER RATIO

15

COMPARISON ATTACHMENT F: PG&E RESULTS

PG&E EC & PG&E GCAP PROPOSALS Except TIER RATIO

BILL DASHBOARD RESULTS AT SCENARIO SETTINGS

BELOW:


REQUIREMENT (PG&E’S EMBEDDED COST)

2. AT 2 FOR ALLOCATION OF ENERGY EFFICIENCY-RELATED PORTIONS

OF GAS PPP SURCHARGE

3. AT 1 FOR PG&E RESIDENTIAL BASELINE ALLOWANCE SEASON

STRUCTURE (PG&E 3 MONTHS, 9-MO. NON-PEAK)

4. AT $15 FOR MINIMUM MONTHLY NON-CARE RESIDENTIAL

TRANSPORTATION CHARGE – BASIC SERVICE (PG&E)


TRANSPORTATION CHARGE – SUPER PEAK SERVICE (PG&E)

6. AT 1.41 FOR RESIDENTIAL BUNDLED TIER RATIO FOR ALL 4 YEARS

(NO CHANGES TO CURRENT STATUS OF TIER RATIO)

7. AT 1 FOR USE OF OCT 2016-SEPT 2017 ACTUAL RECORDED GAS

USAGE

8. AT 1 FOR COST OF GAS TO CALCULATE RESIDENTIAL CORE

PROCUREMENT RATE APPLICABLE TO BUNDLED CUSTOMER BILL

CALCULATIONS

16

1 PG&E

25th Percentile CARE

Bundled System

Average



Territory X (Inner

Valley)

Present Average Monthly Bill

$23.99 $19.18 $19.40


Bill

$23.36 $18.54 $19.47


Bill

$22.73 $18.05 $18.25


Bill

$22.73 $18.05 $18.25


Bill

$22.73 $18.05 $18.25


-1.3% -1.5% -1.5%


2 PG&E

25th Percentile

Non-CARE Bundled

System Average



Territory X (Inner

Valley)



Bill $36.39 $25.67 $34.65


Bill $35.87 $25.33 $34.02


Bill $35.87 $25.33 $34.02


Bill $35.87 $25.33 $34.02


0.9% 0.6% 0.4%


3 PG&E

25th Percentile

Non-CARE Bundled

System Average

(estimated)



Territory X (Inner

Valley)


(Std. Dev.) 25.2% 29.3% 14.5% 24.1%


(Std. Dev.) Yr1 21.6% 23.6% 14.5% 20.4%


(Std. Dev.) Yr2 21.5% 23.1% 14.5% 20.4%


(Std. Dev.) Yr3 21.5% 23.1% 14.5% 20.4%


(Std. Dev.) Yr4 21.5% 23.1% 14.5% 20.4%

Source: Excel Range Row Y28 through AC33, Tab Bill Impact Dashboard.

17

4 PG&E

50th Percentile

CARE Bundled

System Average



Territory X (Inner

Valley)


Proposed Yr1 Average

Monthly Bill $36.35 $32.09 $32.67


Monthly Bill $35.37 $31.23 $31.79


Monthly Bill $35.37 $31.23 $31.79


Monthly Bill $35.37 $31.23 $31.79

Compound Annual % Charge

-1.5% -1.4% -1.3%


5 PG&E

50th Percentile

Non-CARE Bundled

System Average



Territory X (Inner

Valley)



Monthly Bill $51.25 $52.80 $45.30 $53.32


Monthly Bill $50.14 $51.85 $44.10 $52.11


Monthly Bill $50.14 $51.85 $44.10 $52.11


Monthly Bill $50.14 $51.85 $44.10 $52.11


-0.3% -1.2% -0.7%

Source: Excel Range Row C48 through G54, Tab Bill Impact Dashboard

6 PG&E

Std Dev. as % of Avg. Bill

50th Percentile

Non-CARE Bundled

System Average



Territory X (Inner

Valley)


(Std. Dev.) 29.7% 35.1% 21.2% 28.3%


(Std. Dev.) Yr1 21.7% 26.6% 14.6% 20.5%


(Std. Dev.) Yr2 21.6% 26.3% 14.6% 20.5%


(Std. Dev.) Yr3 21.6% 26.3% 14.6% 20.5%


(Std. Dev.) Yr4 21.6% 26.3% 14.6% 20.5%


18

7 PG&E 50th Percentile

Non-CARE Bundled

System Average



Territory X (Inner

Valley)


Differentials

$53.61 $67.80 $31.33 $53.25


Differentials Yr1

$35.67 $47.26 $19.54 $34.42


Differentials Yr2

$34.50 $45.40 $19.03 $33.52


Differentials Yr3

$34.50 $45.40 $19.03 $33.52


Differentials Yr4

$34.50 $45.40 $19.03 $33.52

Source: Excel Range Rows I28 through M33, Tab Bill Impact Dashboard.

8 PG&E

75th Percentile CARE

Bundled System

Average



Territory X (Inner

Valley)



Bill $52.46 $50.29 $49.22


Bill $51.05 $48.93 $47.90


Bill $51.05 $48.93 $47.90


Bill $51.05 $48.93 $47.90


-1.2% -1.1% -1.2%

Source: Excel Range Rows S58 through W64, Tab Bill Impact Dashboard.

9 PG&E

75th Percentile Non-

CARE Bundled System

Average



Territory X (Inner

Valley)



Bill $73.03 $73.41 $77.72


Bill $71.55 $71.45 $75.66


Bill $71.55 $71.45 $75.66


Bill $71.55 $71.45 $75.66


-0.8% -1.2% -1.1%


19

10 PG&E

75th Percentile Non-CARE

Bundled System Average

(estimated) Territory S (Central Valley) Territory T (Coast)

Territory X (Inner

Valley)



Dev.) Yr1 22.4% 25.5% 17.3% 21.1%


Dev.) Yr2 22.2% 25.3% 17.3% 21.1%


Dev.) Yr3 22.2% 25.3% 17.3% 21.1%


Dev.) Yr4 22.2% 25.3% 17.3% 21.1%


11 PG&E

50th Non-

CARE

Bundled

System Avg

50th CARE

Bundled

System Avg

50th

Territory S

(Coast) Non-

CARE

50th Territory

T (Coast) non-

CARE

CARE 25th

PercentileTe

rritory X

CARE 50th

PercentileTe

rritory X

CARE 75th

PercentileTe

rritory X

Present $110.47 $65.44 $124.71 $80.48 $32.06 $56.31 $96.18

Yr 1 $103.96 $61.55 $117.36 $75.44 $31.00 $54.44 $90.61

Yr 2 $101.21 $59.91 $114.25 $73.44 $30.17 $52.99 $88.18

Yr 3 $101.21 $59.91 $114.25 $73.44 $30.17 $52.99 $88.18

Yr 4 $101.21 $59.91 $114.25 $73.44 $30.17 $52.99 $88.18

Source: Excel Range Row I38 through P43, Tab Bill Impact Dashboard.

12 PG&E Compounded Annual % Change in Rates By Residential Segment


Valley)

Territory T

(Coast)

Territory X

(Inner

Valley)




Non-CARE Bundled: 25th Percentile 0.9% 0.6% 0.4%




20

PG

&E

13

Avg

Mo

. B

ills:

50

th

Pe

rce

nti

le

Oct

ob

er

No

vem

be

r D

ece

mb

er

Jan

ua

ry

Fe

bru

ary

M

arc

h

Ap

ril

Ma

y Ju

ne

Ju

ly

Au

gu

st

Se

pte

mb

er

To

tal 1

2

mo

.

Pre

sen

t $

35

.33

$

61

.87

$

11

5.4

8

$1

05

.47

$

66

.46

$

57

.59

$

50

.94

$

32

.67

$

24

.35

$

21

.58

$

21

.32

$

23

.44

$

61

6.5

0

Cu

rre

nt

Pro

po

sed

Sce

na

rio

$3

2.4

3

$6

9.2

1

$1

09

.31

$

10

0.5

8

$6

7.1

2

$6

4.0

4

$4

6.0

4

$3

0.1

1

$2

4.3

0

$2

3.2

2

$2

3.0

0

$2

3.5

1

$6

12

.85

No

n-C

AR

E B

un

dle

d

($2

.91

) $

7.3

4

($6

.17

) ($

4.8

9)

$0

.65

$

6.4

6

($4

.91

) ($

2.5

6)

($0

.05

) $

1.6

4

$1

.68

$

0.0

7

($3

.65

)

CA

RE

Bu

nd

led

($

2.6

7)

$4

.56

($

2.1

2)

($1

.37

) $

0.3

5

$3

.95

($

3.6

9)

($2

.40

) ($

1.5

7)

($0

.77

) ($

0.9

7)

($1

.35

) ($

8.0

5)

% C

ha

ng

e

-8%

1

2%

-5

%

-5%

1

%

11

%

-10

%

-8%

0

%

8%

8

%

0%

3

.9%

O

cto

be

r N

ove

mb

er

De

cem

be

r Ja

nu

ary

F

eb

rua

ry

Ma

rch

A

pri

l M

ay

Jun

e

July

A

ug

ust

S

ep

tem

be

r

Te

rrit

ory

X N

on

-CA

RE

:

25

th P

erc

en

tile

Ch

an

ge

($0

.57

) $

2.7

8

$0

.69

$

0.6

5

$0

.44

$

2.5

0

($2

.63

) $

0.8

8

$3

.39

$

4.3

2

$4

.53

$

3.7

0

$2

0.6

8

Te

rrit

ory

X N

on

-CA

RE

:

75

th P

erc

en

tile

Ch

an

ge

($5

.30

) $

7.4

7

($1

3.5

5)

($1

1.8

8)

($4

.65

) $

9.0

3

($8

.97

) ($

4.7

7)

($2

.64

) ($

1.5

0)

($1

.64

) ($

2.5

0)

($4

0.8

9)

O

cto

be

r N

ove

mb

er

De

cem

be

r Ja

nu

ary

F

eb

rua

ry

Ma

rch

A

pri

l M

ay

Jun

e

July

A

ug

ust

S

ep

tem

be

r

Te

rrit

ory

X C

AR

E:

25

th

Pe

rce

nti

le C

ha

ng

e

$0

.13

$

0.3

5

$0

.28

$

0.2

5

$0

.19

$

0.3

1

($0

.53

) $

0.1

3

$0

.11

$

0.1

0

$0

.10

$

0.1

0

$1

.52

Te

rrit

ory

X C

AR

E:

75

th

Pe

rce

nti

le C

ha

ng

e

($4

.06

) $

7.8

4

($5

.84

) ($

4.5

4)

$0

.50

$

6.8

2

($5

.72

) ($

3.6

5)

($2

.39

) ($

1.6

9)

($1

.84

) ($

2.2

8)

($1

6.8

4)

So

urc

e:

Exc

el R

an

ge

Ro

w C

79

th

rou

gh

P9

0,

Ta

b B

ill I

mp

act

Da

shb

oa

rd.

ORA ATTACHMENT G

COMBINED ORA GCAP RECOMMENDATIONS

10

ORA ATTACHMENT G

COMBINED ORA GCAP RECOMMENDATIONS

BILL IMPACT DASHBOARD RESULTS AT SCENARIO SETTINGS

BELOW:


REQUIREMENT (ORA’S MC DTIM-BASED MDCC & MCAC NCO)









6. AT 1.35 = YR1, 1.30= YR2, 1.25= YR3, 1.20 = YR4 FOR RESIDENTIAL

BUNDLED TIER RATIO FOR EACH YEAR


USAGE



CALCULATIONS

NOTE: ORA Recommendations on Baseline Season Structure not appropriately reflected in Scenario Settings. Refer to Section III.B.2 of ORA Ex. ORA-05.

11

1 ORA Combined 25th Percentile

CARE Bundled

System Average


Valley)

Territory T (Coast) Territory X (Inner

Valley)



Bill

$24.19 $19.27 $20.53


Bill

$23.89 $19.10 $19.31


Bill

$24.19 $19.41 $19.61


Bill

$24.51 $19.73 $19.93

Compound Annual % Change 0.5% 0.7% 0.7%

Source: Excel Range Rows S38 through W44, Tab Bill Impact Dashboard.


Non-CARE Bundled

System Average


Valley)


Valley)



Bill

$35.14 $24.88 $34.09


Bill

$34.68 $24.66 $33.70


Bill

$35.09 $25.05 $34.13


Bill

$35.50 $25.46 $34.58


Source: Excel Range Rows C38 through G44, Tab Bill Impact Dashboard.


Non-CARE Bundled

System Average

(estimated)


Valley)


Valley)


(Std. Dev.)

25.2% 29.3% 14.5% 24.1%


(Std. Dev.) Yr1

22.2% 24.5% 14.5% 20.9%


(Std. Dev.) Yr2

22.6% 25.1% 14.5% 21.3%


(Std. Dev.) Yr3

23.0% 25.6% 14.5% 21.7%


(Std. Dev.) Yr4

23.5% 26.3% 14.5% 22.2%

Source: Excel Range Rows Y28 through AC33, Tab Bill Impact Dashboard.

12


CARE Bundled

System Average


Valley)


Valley)



Bill

$37.44 $33.16 $33.75


Bill

$36.80 $32.69 $33.26


Bill

$37.08 $33.03 $33.61


Bill

$37.37 $33.39 $33.96

-0.1% 0.2% 0.3%



Non-CARE Bundled

System Average


Valley)


Valley)



Bill

$51.92 $52.88 $46.73 $54.27


Bill

$50.98 $51.84 $46.03 $53.28


Bill

$51.30 $52.08 $46.48 $53.61


Bill

$51.63 $52.33 $46.93 $53.96

-0.1% 0.3% 0.2%


6 ORA Combined Std Dev. as

% of Avg. Bill

50th Percentile

Non-CARE Bundled

System Average


Valley)


Valley)


(Std. Dev.)

29.7% 35.1% 21.2% 28.3%


(Std. Dev.) Yr1

22.1% 27.0% 15.1% 20.8%


(Std. Dev.) Yr2

22.4% 27.3% 15.5% 21.1%


(Std. Dev.) Yr3

22.8% 27.5% 16.0% 21.5%


(Std. Dev.) Yr4

23.1% 27.8% 16.5% 21.9%


13


Non-CARE

Bundled System

Average

Territory S

(Central Valley)

Territory T

(Coast)

Territory X

(Inner Valley)


Differentials

$53.61 $67.80 $31.33 $53.25


Differentials Yr1

$38.01 $49.93 $21.21 $36.62


Differentials Yr2

$38.34 $49.88 $21.88 $37.10


Differentials Yr3

$39.61 $51.07 $23.08 $38.51


Differentials Yr4

$40.93 $52.29 $24.33 $39.96



CARE Bundled

System Average


Valley)


Valley)



Bill

$53.64 $51.51 $50.49


Bill

$52.36 $50.36 $49.44


Bill

$52.40 $50.48 $49.62


Bill

$52.41 $50.59 $49.81

-0.6% -0.3% -0.2%



Non-CARE Bundled

System Average


Valley)


Valley)



Bill

$73.98 $74.93 $79.32


Bill

$72.11 $73.09 $77.34


Bill

$72.01 $73.05 $77.27


Bill

$71.91 $73.00 $77.20

-0.7% -0.6% -0.6%


14


Non-CARE Bundled

System Average

(estimated)


Valley)


Valley)


(Std. Dev.)

29.0% 32.8% 22.7% 27.7%


(Std. Dev.) Yr1

22.5% 25.7% 17.4% 21.2%


(Std. Dev.) Yr2

22.6% 25.7% 17.4% 21.3%


(Std. Dev.) Yr3

22.7% 25.8% 17.5% 21.4%


(Std. Dev.) Yr4

22.8% 26.0% 17.6% 21.6%

Source: Excel Range RowS28 through W33, Tab Bill Impact Dashboard.

11 ORA

Combined

50th Non-

CARE

Bundled

System Avg

50th CARE

Bundled

System

Avg

50th

Territory S

(Coast)

Non-CARE

50th

Territory T

(Coast)

non-CARE

CARE 25th

PercentileTerritory

X

CARE 50th

PercentileTerritory

X

CARE 75th

PercentileTerritory

X

Present $110.47 $65.44 $124.71 $80.48 $32.06 $56.31 $96.18

Yr 1 $107.06 $63.85 $120.51 $78.22 $32.22 $56.59 $93.25

Yr 2 $105.30 $63.16 $118.21 $77.42 $31.94 $56.09 $91.58

Yr 3 $106.14 $64.06 $118.83 $78.54 $32.45 $56.99 $92.20

Yr 4 $107.01 $64.98 $119.47 $79.70 $32.98 $57.92 $92.84

Source: Excel Range RowI38 through P43, Tab Bill Impact Dashboard.

12 ORA

Combined



Valley)


Valley)

CAREBundled: 25th Percentile 0.5% 0.7% 0.7%

CAREBundled: 50th Percentile -0.1% 0.2% 0.3%



Non-CARE Bundled: 50th Percentile -0.1% 0.3% 0.2%



15

O

RA

MA

RG

INA

L C

OST

AD

JUST

ED

13

OR

A C

om

bin

ed

Avg

Mo

. B

ills:

50

th

Pe

rce

nti

le

Oct

ob

er

No

vem

be

r D

ece

mb

er

Jan

ua

ry

Fe

bru

ary

M

arc

h

Ap

ril

Ma

y Ju

ne

Ju

ly

Au

gu

st

Se

pte

mb

er

To

tal

Pre

sen

t $

35

.33

$

61

.87

$

11

5.4

8

$1

05

.47

$

66

.46

$

57

.59

$

50

.94

$

32

.67

$

24

.35

$

21

.58

$

21

.32

$

23

.44

$

61

6.5

0

Cu

rre

nt

Pro

po

sed

Sce

na

rio

$3

3.0

2

$7

0.5

3

$1

11

.46

$

10

2.5

6

$6

8.4

4

$6

5.2

6

$4

6.9

0

$3

0.6

5

$2

3.9

4

$2

1.8

6

$2

1.6

7

$2

3.2

5

$6

19

.53

No

n-C

AR

E B

un

dle

d

($2

.31

) $

8.6

6

($4

.02

) ($

2.9

1)

$1

.97

$

7.6

8

($4

.05

) ($

2.0

2)

($0

.41

) $

0.2

8

$0

.35

($

0.1

9)

$3

.02

CA

RE

Bu

nd

led

($

2.1

4)

$5

.50

($

0.7

7)

($0

.14

) $

1.2

1

$4

.82

($

3.0

2)

($1

.91

) ($

1.1

7)

($0

.41

) ($

0.6

0)

($0

.96

) $

0.4

1

% C

ha

ng

e

-7%

1

4%

-3

%

-3%

3

%

13

%

-8%

-6

%

-2%

1

%

2%

-1

%

4%

O

cto

be

r N

ove

mb

er

De

cem

be

r Ja

nu

ary

F

eb

rua

ry

Ma

rch

A

pri

l M

ay

Jun

e

July

A

ug

ust

S

ep

tem

be

r

Te

rrit

ory

X N

on

-CA

RE

:

25

th P

erc

en

tile

Ch

an

ge

($0

.11

) $

3.6

3

$2

.03

$

1.9

2

$1

.30

$

3.3

2

($2

.04

) $

0.4

3

$0

.54

$

0.5

0

$0

.49

$

0.5

3

$1

2.5

5

Te

rrit

ory

X N

on

-CA

RE

:

75

th P

erc

en

tile

Ch

an

ge

($4

.35

) $

9.6

4

($1

0.3

0)

($8

.86

) ($

2.6

0)

$1

0.9

9

($7

.52

) ($

3.8

9)

($2

.04

) ($

0.9

9)

($1

.12

) ($

1.9

2)

($2

2.9

7)

O

cto

be

r N

ove

mb

er

De

cem

be

r Ja

nu

ary

F

eb

rua

ry

Ma

rch

A

pri

l M

ay

Jun

e

July

A

ug

ust

S

ep

tem

be

r

Te

rrit

ory

X C

AR

E:

25

th

Pe

rce

nti

le C

ha

ng

e

$0

.45

$

0.8

3

$0

.96

$

0.8

8

$0

.65

$

0.7

8

($0

.15

) $

0.4

5

$0

.37

$

0.3

4

$0

.33

$

0.3

6

$6

.26

Te

rrit

ory

X C

AR

E:

75

th

Pe

rce

nti

le C

ha

ng

e

($3

.32

) $

9.2

2

($3

.90

) ($

2.7

8)

$1

.75

$

8.0

8

($4

.75

) ($

2.9

6)

($1

.88

) ($

1.2

5)

($1

.39

) ($

1.7

8)

($4

.95

)

So

urc

e:

Exc

el R

an

ge

Ro

w C

79

th

rou

gh

P9

0,

Ta

b B

ill I

mp

act

Da

shb

oa

rd.

ORA ATTACHMENT H

PG&E COMBINED GCAP PROPOSALS

27

ORA ATTACHMENT H

PG&E COMBINED GCAP PROPOSALS

BILL IMPACT DASHBOARD RESULTS AT SCENARIO SETTINGS BELOW:


REQUIREMENT (PG&E’S EMBEDDED COST)









6. AT 1.35 = YR1, 1.30= YR2, 1.25= YR3, 1.20 = YR4 FOR RESIDENTIAL

BUNDLED TIER RATIO FOR EACH YEAR


USAGE



CALCULATIONS

28

1 PG&E Combined

25th Percentile CARE Bundled System Average

Territory S (Central Valley) Territory T (Coast)

Territory X (Inner Valley)








2 PG&E Combined












3 PG&E Combined


Bundled System Average (estimated)




Proposed Winter Bill Volatility (Std. Dev.) Yr1 22.1% 24.5% 14.5% 20.9%




Source: Excel Range Row Y28 through AC 33.

29

4 PG&E Combined









Compounded Annual % Change -0.6% -0.3% -0.2%


5 PG&E Combined












6 PG&E Combined Std Dev. as % of Avg. Bill











30

7 PG&E Combined

50th Percentile Non-CARE Bundled System Average



Present November to December Bill Differentials $53.61 $67.80 $31.33 $53.25

Proposed November to December Bill Differentials Yr1 $37.18 $48.95 $20.80 $35.90





8 PG&E Combined










Source: Excel Range Row S58 through W64, Tab Bill Impact Daashboard.

9 PG&E Combined












31

10 PG&E Combined



(estimated) Territory S (Central

Valley) Territory T (Coast) Territory X (Inner

Valley)







11 PG&E Combined

50th Non-CARE Bundled System

Avg

50th CARE Bundled

System Avg

50th Territory S

(Coast) Non-CARE

50th Territory T

(Coast) non-CARE

CARE 25th Percentile

Territory X

CARE 50th Percentile

Territory X

CARE 75th

Percentile Territory

X

Present $110.47 $65.44 $124.71 $80.48 $32.06 $56.31 $96.18

Yr 1 $104.94 $62.55 $118.12 $76.67 $31.56 $55.43 $91.34

Yr 2 $103.06 $61.78 $115.69 $75.78 $31.24 $54.86 $89.57

Yr 3 $103.99 $62.72 $116.42 $76.96 $31.77 $55.80 $90.27

Yr 4 $104.94 $63.69 $117.16 $78.17 $32.33 $56.77 $90.99

Source: Excel Range Row I38 through P43, Tab Bill Impact Dashboard.

12 PG&E Combined


Territory S (Central Valley)

Territory T (Coast)


CAREBundled: 25th Percentile 0.0% 0.2% 0.2%







32

PG

&E

Co

mb

ine

d

13

Avg

Mo

. B

ills:

50

th P

erc

en

tile

Oct

ob

er

No

vem

be

r D

ece

mb

er

Jan

ua

ry

Fe

bru

ary

M

arc

h

Ap

ril

Ma

y Ju

ne

Ju

ly

Au

gu

st

Se

pte

mb

er

To

tal 1

2

mo

.

Pre

sen

t $

35

.33

$

61

.87

$

11

5.4

8

$1

05

.47

$

66

.46

$

57

.59

$

50

.94

$

32

.67

$

24

.35

$

21

.58

$

21

.32

$

23

.44

$

61

6.5

0

Cu

rre

nt

Pro

po

sed

Sce

na

rio

$3

2.4

3

$6

9.2

1

$1

09

.31

$

10

0.5

8

$6

7.1

2

$6

4.0

4

$4

6.0

4

$3

0.1

1

$2

4.3

0

$2

3.2

2

$2

3.0

0

$2

3.5

1

$6

12

.85

No

n-C

AR

E

Bu

nd

led

($2

.91

) $

7.3

4

($6

.17

) ($

4.8

9)

$0

.65

$

6.4

6

($4

.91

) ($

2.5

6)

($0

.05

) $

1.6

4

$1

.68

$

0.0

7

($3

.65

)

CA

RE

Bu

nd

led

($

2.6

7)

$4

.56

($

2.1

2)

($1

.37

) $

0.3

5

$3

.95

($

3.6

9)

($2

.40

) ($

1.5

7)

($0

.77

) ($

0.9

7)

($1

.35

) ($

8.0

5)

% C

ha

ng

e

-8.2

%

11

.9%

-5

.3%

-4

.6%

1

.0%

1

1.2

%

-9.6

%

-7.8

%

-0.2

%

7.6

%

7.9

%

0.3

%

3.9

%

O

cto

be

r N

ove

mb

er

De

cem

be

r Ja

nu

ary

F

eb

rua

ry

Ma

rch

A

pri

l M

ay

Jun

e

July

A

ug

ust

S

ep

tem

be

r

Te

rrit

ory

X N

on

-

CA

RE

: 2

5th

Pe

rce

nti

le

Ch

an

ge

($0

.57

) $

2.7

8

$0

.69

$

0.6

5

$0

.44

$

2.5

0

($2

.63

) $

0.8

8

$3

.39

$

4.3

2

$4

.53

$

3.7

0

$2

0.6

8

Te

rrit

ory

X N

on

-

CA

RE

: 7

5th

Pe

rce

nti

le

Ch

an

ge

($5

.30

) $

7.4

7

($1

3.5

5)

($1

1.8

8)

($4

.65

) $

9.0

3

($8

.97

) ($

4.7

7)

($2

.64

) ($

1.5

0)

($1

.64

) ($

2.5

0)

($4

0.8

9)

O

cto

be

r N

ove

mb

er

De

cem

be

r Ja

nu

ary

F

eb

rua

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ay

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$0

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rd.

ORA ATTACHMENT I

COMPARISON OF ORA RECOMMENDATIONS VERSUS

PG&E PROPOSALS ON COMBINED BASIS

12-MONTH SUMMARY TOTAL OF TABLE 13

33

12-Mon Total Summary

Avg Mo. Bills: 50th Percentile ORA PG&E DIFFERENCE ORA >

PG&E

Present $616.50 $616.50 $ -

Current Proposed Scenario $619.53 $612.85 $6.68

Non-CARE Bundled $3.02 $(3.65) $6.68

CARE Bundled $0.41 $(8.05) $8.46

% Change 3.81% 3.93% -0.12%

Territory X Non-CARE: 25th Percentile Change $12.55 $20.68 $(8.13)

Territory X Non-CARE: 75th Percentile Change $(22.97) $(40.89) $17.92

Territory X CARE: 25th Percentile Change $6.26 $1.52 $4.55

Territory X CARE: 75th Percentile Change $(4.95) $(16.84) $11.39

Source: ORA column 12-Month Summary of Excel Range Row C79 through P90, Tab Bill Impact Dashboard, from ORA &

PG&E GCAP ENHANCED TOOL AT Scenario Settings described for Attachment G in ORA Exhibit ORA-05. PG&E column 12-

Month Summary of Excel Range Row C79 through P90, Tab Bill Impact Dashboard, from PG&E GCAP ENHANCED TOOL AT

Scenario Settings described for Attachment H in ORA Exhibit ORA-05.

ORA ATTACHMENT J

• Residential CARE and Non-CARE Tier Rates

• Illustrative Class Average Rates

• Residential/Small Commercial Bill Impact

• Comparison of Rates in Bill Insert Tables

2

PG&E Proposal

Source: PG&E Workpapers GCAP 2018, RD Model, Tab Res RD Tab., at Excel Cell Range B62 through F73.

ORA Recommendation

Source: ORA Workpapers GCAP 2018, RD Model, Tab Res RD Tab., at Excel Cell Range B62 through F73.

Pre-MMTC Post-MMTC

Non-CARE Non-CARE Residential Non-CARE

Residential Residential Procurement Bundled

Transportation Transportation Rate Rate

Residential Tier I rates $.98137 $.87999 $.44816 $1.32815

Residential Tier II rates $1.35315 $1.34484 $.44816 $1.79300

Avg. Non-CARE Residential Rate (Bundled & Transport-only) $1.11781 $1.05058 $.44816 $1.49874

Tier 2/Tier 1 Ratio 1.379 1.528 1.000 1.35000 Effective Ratio

Non-CARE CARE Impacting

Residential Tier I Distribution-Level rates $.65614 $.66710 Bill Volatility

Residential Tier II Distribution-Level rates $.90471 $.91982

Avg. Non-CARE Residential distribution Rate (Bundled & Transport-only) $.74736 $.74736

Pre-MMTC Post-MMTC

Non-CARE Non-CARE Residential Non-CARE

Residential Residential Procurement Bundled

Transportation Transportation Rate Rate

Residential Tier I rates $.91700 $.90872 $.44816 $1.35688

Residential Tier II rates $1.38402 $1.38362 $.44816 $1.83178

Avg. Non-CARE Residential Rate (Bundled & Transport-only) $1.08839 $1.08300 $.44816 $1.53116

Tier 2/Tier 1 Ratio 1.509 1.523 1.000 1.35000

Non-CARE CARE

Residential Tier I Distribution-Level rates $.60633 $.61947

Residential Tier II Distribution-Level rates $.91513 $.93496

Avg. Non-CARE Residential distribution Rate (Bundled & Transport-only) $.71966 $.71967

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om

pan

y -

2018 G

CA

P A

.17-0

9-0

06

M

ay 2

018

Da

te

Ave

rag

e R

es

Us

e (

Th

erm

) W

A A

ve

rag

e R

es

Us

e (

Th

erm

)

1/1

/1995

81.9

193

1

105.7

84

4

2/1

/1995

65.2

652

5

73.1

724

2

3/1

/1995

60.3

229

58.7

473

9

4/1

/1995

49.0

645

3

44.9

143

4

5/1

/1995

38.6

136

6

36.9

175

8

6/1

/1995

29.9

402

8

29.2

646

9

7/1

/1995

24.3

827

24.7

345

8/1

/1995

23.3

429

3

23.2

806

7

9/1

/1995

25.1

357

3

25.3

194

8

10/1

/199

5

30.4

873

4

30.9

272

2

11/1

/199

5

44.6

576

9

57.1

102

1

12/1

/199

5

70.1

942

101.6

99

4

1/1

/1996

82.5

963

7

98.3

267

6

2/1

/1996

68.7

941

4

77.2

412

9

3/1

/1996

55.5

485

57.0

382

2

4/1

/1996

41.8

679

1

41.9

900

7

5/1

/1996

31.5

553

6

32.7

178

5

6/1

/1996

27.6

843

5

27.4

367

6

7/1

/1996

24.6

325

8

24.5

430

3

8/1

/1996

23.7

079

5

23.4

731

1

9/1

/1996

26.5

325

8

26.1

933

4

10/1

/199

6

37.6

568

1

34.5

469

7

11/1

/199

6

60.9

748

6

64.4

768

1

18

12/1

/199

6

77.8

692

6

104.6

64

7

1/1

/1997

90.4

784

4

97.7

885

5

2/1

/1997

73.6

548

77.4

136

7

3/1

/1997

52.1

379

2

55.1

591

2

4/1

/1997

38.7

847

8

41.1

219

8

5/1

/1997

28.8

636

7

31.4

161

1

6/1

/1997

25.5

375

9

26.4

591

7/1

/1997

24.2

082

24.4

207

3

8/1

/1997

23.2

221

7

23.5

743

9

9/1

/1997

24.0

183

4

24.5

549

3

10/1

/199

7

33.3

986

4

33.6

264

7

11/1

/199

7

57.0

146

66.6

805

5

12/1

/199

7

92.2

722

98.6

914

7

1/1

/1998

87.4

822

1

107.0

14

2/1

/1998

85.2

502

4

81.2

488

3

3/1

/1998

63.5

342

61.2

321

7

4/1

/1998

50.5

181

6

46.2

450

2

5/1

/1998

41.1

318

4

38.4

938

4

6/1

/1998

30.3

499

1

30.1

077

7/1

/1998

25.3

351

2

25.3

597

4

8/1

/1998

23.4

979

4

23.6

582

3

9/1

/1998

26.2

379

6

26.3

337

10/1

/199

8

36.2

060

9

34.0

489

4

11/1

/199

8

67.2

738

1

65.5

804

1

12/1

/199

8

104.8

89

7

93.1

244

7

1/1

/1999

102.0

86

4

97.7

446

2

2/1

/1999

90.6

744

5

75.8

361

3

3/1

/1999

76.3

881

6

60.9

037

9

4/1

/1999

53.2

160

4

46.8

698

9

19

5/1

/1999

38.4

505

7

34.9

172

8

6/1

/1999

30.4

835

6

29.1

021

7

7/1

/1999

25.8

087

1

25.2

753

9

8/1

/1999

25.4

974

2

25.2

939

4

9/1

/1999

26.2

130

1

26.2

448

6

10/1

/199

9

31.4

881

1

32.5

136

4

11/1

/199

9

59.7

736

1

64.7

757

4

12/1

/199

9

89.1

392

2

93.5

292

1

1/1

/2000

82.7

659

1

99.3

212

2/1

/2000

77.2

988

4

79.2

948

3

3/1

/2000

54.9

079

5

53.0

6

4/1

/2000

39.0

604

4

40.1

762

1

5/1

/2000

33.9

178

5

33.1

444

6

6/1

/2000

26.4

385

4

26.5

607

9

7/1

/2000

25.1

816

5

24.8

054

2

8/1

/2000

24.4

009

7

23.9

257

7

9/1

/2000

25.5

847

3

25.3

620

7

10/1

/200

0

37.4

214

9

35.8

560

5

11/1

/200

0

75.7

830

9

57.5

015

3

12/1

/200

0

84.7

174

8

92.6

354

9

1/1

/2001

92.5

096

5

81.7

749

2

2/1

/2001

79.0

871

3

65.5

852

8

3/1

/2001

47.7

382

3

46.0

979

9

4/1

/2001

40.7

102

3

36.4

966

1

5/1

/2001

26.6

169

4

27.9

413

6

6/1

/2001

22.7

781

6

23.1

012

7/1

/2001

22.4

500

8

22.2

979

7

8/1

/2001

22.1

085

6

21.8

577

9/1

/2001

23.6

944

23.4

996

20

10/1

/200

1

27.2

288

3

28.1

976

7

11/1

/200

1

50.4

464

7

55.4

972

4

12/1

/200

1

79.4

289

4

90.7

326

4

1/1

/2002

88.6

365

9

79.9

851

2/1

/2002

70.9

873

2

64.2

298

2

3/1

/2002

55.7

392

4

50.3

720

7

4/1

/2002

40.4

697

5

39.4

319

5/1

/2002

32.6

155

6

30.2

507

6

6/1

/2002

24.8

952

1

24.6

246

8

7/1

/2002

22.4

704

6

22.3

236

3

8/1

/2002

22.6

573

8

22.3

568

2

9/1

/2002

23.4

753

5

23.3

502

9

10/1

/200

2

32.6

735

2

31.2

535

4

11/1

/200

2

54.1

418

1

59.1

302

8

12/1

/200

2

73.5

797

93.1

422

6

1/1

/2003

72.7

616

9

70.7

628

2/1

/2003

68.1

525

8

68.0

012

1

3/1

/2003

49.1

620

1

49.1

351

4/1

/2003

47.2

589

5

47.2

439

3

5/1

/2003

33.5

765

8

33.5

885

5

6/1

/2003

24.6

658

3

24.6

825

3

7/1

/2003

21.3

634

9

21.3

731

4

8/1

/2003

20.8

271

2

20.8

144

8

9/1

/2003

22.0

910

8

22.0

809

10/1

/200

3

28.3

354

7

27.5

954

8

11/1

/200

3

57.5

574

5

56.0

675

8

12/1

/200

3

81.3

168

2

80.9

029

1/1

/2004

86.2

985

1

83.4

466

2/1

/2004

73.5

613

9

74.3

367

3

21

3/1

/2004

41.8

939

2

41.8

926

1

4/1

/2004

33.8

712

33.6

366

4

5/1

/2004

27.0

408

4

27.1

426

4

6/1

/2004

24.1

306

5

24.1

898

9

7/1

/2004

21.6

217

21.6

143

3

8/1

/2004

20.5

206

3

20.5

211

4

9/1

/2004

22.2

146

2

22.1

559

7

10/1

/200

4

32.6

366

7

31.7

027

11/1

/200

4

61.4

898

59.7

035

9

12/1

/200

4

80.4

057

6

76.8

810

2

1/1

/2005

88.5

638

2

85.5

775

5

2/1

/2005

62.9

787

2

65.9

687

6

3/1

/2005

45.9

918

4

45.9

213

8

4/1

/2005

41.4

014

7

41.6

930

4

5/1

/2005

28.9

617

3

29.1

634

6/1

/2005

24.2

307

1

24.2

943

1

7/1

/2005

20.7

874

2

20.8

147

8

8/1

/2005

20.8

718

7

20.8

510

8

9/1

/2005

24.2

569

3

24.2

046

1

10/1

/200

5

27.4

286

3

27.0

038

2

11/1

/200

5

47.1

058

4

45.6

864

3

12/1

/200

5

65.3

383

63.8

736

5

1/1

/2006

67.8

481

3

66.6

185

5

2/1

/2006

66.2

097

9

66.0

361

3/1

/2006

65.2

658

1

63.7

626

8

4/1

/2006

44.5

193

45.0

706

8

5/1

/2006

26.4

127

6

26.5

784

5

6/1

/2006

22.3

418

6

22.4

089

7/1

/2006

19.2

194

7

19.2

392

9

22

8/1

/2006

19.6

827

4

19.6

189

1

9/1

/2006

22.5

745

1

22.4

547

2

10/1

/200

6

27.5

262

1

27.1

707

5

11/1

/200

6

48.9

726

4

45.7

739

1

12/1

/200

6

77.3

863

7

74.7

982

4

1/1

/2007

91.1

61

91.1

602

1

2/1

/2007

66.0

683

4

68.0

330

9

3/1

/2007

42.5

994

5

42.5

868

5

4/1

/2007

36.1

235

1

36.1

568

9

5/1

/2007

28.1

134

8

28.5

740

7

6/1

/2007

22.8

425

6

22.9

684

6

7/1

/2007

20.0

470

7

20.0

724

8

8/1

/2007

19.4

823

3

19.4

727

5

9/1

/2007

21.5

481

6

21.2

528

7

10/1

/200

7

28.3

101

1

27.8

241

4

11/1

/200

7

44.1

659

1

40.2

442

6

12/1

/200

7

76.8

054

2

72.3

941

7

1/1

/2008

84.8

053

3

85.6

895

9

2/1

/2008

72.7

000

5

77.5

641

4

3/1

/2008

48.4

417

6

49.3

695

1

4/1

/2008

40.4

810

9

41.4

903

7

5/1

/2008

28.3

216

9

29.0

067

3

6/1

/2008

22.5

777

2

22.9

173

1

7/1

/2008

19.9

242

5

19.9

627

1

8/1

/2008

19.2

656

6

19.3

299

6

9/1

/2008

19.9

207

4

19.7

311

6

10/1

/200

8

24.0

304

3

22.8

598

1

11/1

/200

8

38.4

040

4

34.9

479

3

12/1

/200

8

75.8

162

67.5

316

3

23

1/1

/2009

78.5

995

9

85.4

734

2/1

/2009

69.0

977

8

69.8

800

1

3/1

/2009

52.0

499

1

53.8

313

4

4/1

/2009

37.5

541

5

38.4

651

9

5/1

/2009

27.0

297

7

27.4

949

9

6/1

/2009

22.3

081

7

22.5

168

2

7/1

/2009

20.0

128

8

20.0

333

6

8/1

/2009

19.0

794

1

19.0

539

1

9/1

/2009

20.1

824

7

19.9

353

8

10/1

/200

9

25.8

617

8

25.1

658

7

11/1

/200

9

49.5

499

4

42.1

723

3

12/1

/200

9

78.6

498

2

79.2

844

3

1/1

/2010

77.9

712

7

79.5

852

3

2/1

/2010

64.1

587

7

65.2

823

3/1

/2010

53.3

246

1

54.1

447

4/1

/2010

41.8

334

8

42.9

511

9

5/1

/2010

31.5

444

5

32.0

289

6

6/1

/2010

23.7

557

8

24.1

763

1

7/1

/2010

21.0

011

4

21.0

586

1

8/1

/2010

21.3

333

4

21.3

596

3

9/1

/2010

20.8

230

9

20.7

999

8

10/1

/201

0

24.9

967

3

24.2

237

9

11/1

/201

0

51.4

645

5

47.2

516

9

12/1

/201

0

70.2

760

2

65.7

478

4

1/1

/2011

78.5

957

5

79.4

467

5

2/1

/2011

70.7

089

1

68.9

200

9

3/1

/2011

58.8

786

7

61.0

110

5

4/1

/2011

40.7

750

5

42.3

946

9

5/1

/2011

32.0

398

1

32.1

227

7

24

6/1

/2011

25.3

807

1

25.9

979

7

7/1

/2011

20.2

301

1

20.3

125

1

8/1

/2011

19.5

77

19.5

221

6

9/1

/2011

20.3

919

7

20.3

091

2

10/1

/201

1

24.5

177

23.3

437

8

11/1

/201

1

52.0

291

1

47.6

624

4

12/1

/201

1

77.6

425

9

70.6

689

5

1/1

/2012

78.7

887

5

82.3

870

7

2/1

/2012

63.3

468

9

65.0

142

7

3/1

/2012

55.8

014

4

55.9

297

8

4/1

/2012

41.1

456

3

44.3

045

5/1

/2012

25.4

923

8

25.8

846

8

6/1

/2012

22.1

155

9

22.4

441

9

7/1

/2012

20.0

194

1

20.1

768

9

8/1

/2012

19.0

504

1

18.9

260

5

9/1

/2012

20.8

036

5

20.6

111

2

10/1

/201

2

23.4

267

6

22.6

460

4

11/1

/201

2

42.1

242

3

39.3

567

8

12/1

/201

2

71.4

391

60.8

116

7

1/1

/2013

89.7

403

6

93.3

449

2

2/1

/2013

69.5

367

1

73.9

372

1

3/1

/2013

43.8

135

4

47.2

070

6

4/1

/2013

30.2

923

5

30.8

835

8

5/1

/2013

23.2

233

6

23.3

350

4

6/1

/2013

20.7

944

5

21.0

747

4

7/1

/2013

18.9

044

5

18.9

347

1

8/1

/2013

18.5

646

2

18.6

570

2

9/1

/2013

19.2

072

8

19.3

438

8

10/1

/201

3

25.3

930

5

24.0

618

8

25

11/1

/201

3

45.9

459

4

44.5

398

5

12/1

/201

3

79.2

896

2

73.5

130

9

1/1

/2014

68.3

049

7

81.9

740

7

2/1

/2014

53.1

431

2

56.2

629

9

3/1

/2014

35.9

503

8

44.2

466

4/1

/2014

30.4

648

8

32.7

784

5

5/1

/2014

22.3

203

3

23.6

527

9

6/1

/2014

19.3

571

4

19.5

106

7/1

/2014

17.5

528

8

17.8

569

7

8/1

/2014

17.3

996

8

17.7

291

4

9/1

/2014

17.2

586

4

17.8

138

3

10/1

/201

4

20.1

253

1

21.2

194

7

11/1

/201

4

35.9

33

41.8

625

8

12/1

/201

4

55.5

146

6

74.4

260

6

1/1

/2015

65.9

804

9

79.0

848

1

2/1

/2015

45.7

879

9

53.5

083

3

3/1

/2015

31.9

277

8

38.0

209

9

4/1

/2015

28.2

227

4

29.6

130

8

5/1

/2015

24.2

004

2

24.8

807

4

6/1

/2015

18.4

666

4

18.7

402

3

7/1

/2015

15.8

798

16.2

131

2

8/1

/2015

16.0

106

2

16.2

836

4

9/1

/2015

16.6

830

3

17.0

016

6

10/1

/201

5

18.9

916

4

20.3

562

9

11/1

/201

5

47.7

790

4

42.5

579

9

12/1

/201

5

72.6

106

4

67.1

265

9

1/1

/2016

70.8

988

1

81.9

628

2/1

/2016

47.9

037

4

55.0

001

3

3/1

/2016

37.1

982

3

43.1

307

9

26

4/1

/2016

28.2

249

2

31.5

655

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18.6

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79.7

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41.9

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IX A

1

1. Background on Marginal Cost and Embedded Cost 1 Methodologies 2

PG&E provides information on marginal cost in Appendix A of its GCAP 3

testimony and on embedded cost in Chapter 3 of its testimony. ORA agrees with 4

PG&E’s basic description of Marginal Cost methods provided in Appendix A. ORA 5

provides the following background in this section for reference. 6

There are generally two broad types of cost allocation methodologies that 7

have been used in California. One method uses embedded cost studies while the 8

other uses marginal cost studies.350 PG&E’s Gas Transmission and Storage 9

(GT&S) services are allocated based on the Embedded Cost (EC) method while the 10

Gas Distribution service is based on the Long Run Marginal Cost (LRMC) method.351 11

In D.92749, the Commission first established the marginal cost framework for 12

electric service where marginal costs were defined to represent the cost of providing 13

an additional unit of electric service over and above any currently being produced or 14

served.352 In D.92749, the Commission distinguished between marginal costs in the 15

short run and long run given that the production costs to meet a change in output are 16

different based on the ability of the producer to adjust the factors of production.353 In 17

the short run, plant is considered fixed and the producer can only run existing plant 18

more or less, or buy or sell more or less electricity.354 The short run marginal cost is 19

the change in the variable operating cost with respect to changes in output.355 In the 20

long run the plant capacity can be adjusted to minimize the total costs of producing 21

350

Embedded cost studies use the utility’s audited books from the Uniform System of Accounts while marginal cost studies make use of reasonable estimates of the utility’s marginal cost of its primary functions required to continue providing service to its customers. In marginal cost studies, embedded costs are irrelevant to the decision to invest because those costs are considered spent.

351 D.09-11-006.

352 See D.92749 in OII 67 on the Commission’s Investigation into the methodology for the calculation

of marginal costs of electric service. This is the 1981 decision where the Commission first adopted a marginal cost framework. The adopted methodology is found in Appendix B of the decision.

353 D.92749, Appendix B.

354 Id.

355 Id.

2

the new output requirement.356 This is the underlying marginal cost framework 1

behind LRMC. 2

The Commission first adopted the LRMC methodology for California natural 3

gas transportation service in D.92-12-058.357 For natural gas transportation service 4

of the respondent California gas utilities, the Commission states that “marginal costs 5

are forward-looking costs: they reflect the costs a utility will incur to meet new 6

demand for its services.”358 According to the Commission definition, “LRMC 7

captures the cost of new facilities as well as the short-term marginal costs of daily 8

operating requirements.”359 9

In terms of the criterion that causes a utility to need more new capacity (and 10

thus cause the need to incur more cost), the Commission adopted marginal demand 11

measures (MDMs) for demand-related costs.360 The Commission adopted the 12

following MDMs for PG&E for purposes of computing and allocating the marginal 13

cost revenues for cost allocation: cold year peak day for gas distribution.361 14

The Applicant’s gas distribution marginal costs have two major functional cost 15

categories: distribution demand-related and customer-related marginal costs. Each 16

of these functional cost categories has two components: a capital-related cost 17

component and an operation and maintenance (O&M) expense cost component. 18

The discussion in this section is divided into four sub-parts: the customer-related 19

marginal costs, the derivation of the utility’s distribution demand-related marginal 20

costs, the direct O&M and other marginal cost loaders and the derivation of marginal 21

cost revenues. 22

356

Id.

357 D.92-12-058, Finding of Fact # 1.

358 D.92-12-058, p. 7.

359 D.92-12-058, p. 7.

360 D.92-12-058, p. 21.

361 D.92-12-058, Finding of Fact #25 Conclusion of Law #2(d) and also shown in Table 1, p. 31.

3

(A) Customer-Related Marginal Costs 1

The Commission defines marginal customer costs as the cost of customers’ 2

access to the utility’s gas system.362 The costs would include the components for: 3

(1) the investment cost of facilities to connect a customer to the system: the service 4

line, regulator, and meter (SRM); and (2) the ongoing O&M expense associated with 5

customer accounting.363 For the new customers, the SRM cost is the one-time hook 6

up costs to gain access to the utilities’ gas system.364 The SRM costs are identified 7

as customer costs since they are completely dedicated to providing gas service to a 8

single customer or cluster of customers for access to the system. The Commission 9

stated:365 10

DRA's Service I Regulator, and Meter (SRM) method draws the -11 brightest line between customer and demand related costs, thereby 12 providing a simple, but accurate basis for calculating marginal 13 customer costs. 14

PG&E uses the term Marginal Customer Access Costs (MCAC) to refer to 15

both the capital-related and the ongoing expense cost component of marginal 16

customer costs.366 The marginal capital costs of MCAC refer to the costs associated 17

with connecting customers to PG&E’s gas system (which is the SRM, or what PG&E 18

collectively refers to as the “connection equipment”) while the ongoing marginal 19

expense cost portion refers to costs associated with the Revenue Cycle Services 20

(RCS).367 21

According to PG&E, it has developed a new approach for computing marginal 22

costs of connecting new customers that makes use of costs computed on the basis 23

of actual field-produced job cost estimates from customer contracts.368 The specific 24

362

D.95-12-053, p. 29.

363 D.95-12-053, p. 29.

364 D.92-12-058, Finding of Fact # 46.

365 D.92-12-058, Finding of Fact # 41.

366 Appendix A, PG&E GCAP Testimony in A.17-09-006 (Revised for Errata), p. A-1.

367 Id. According to PG&E, the ongoing expense in RCS relates to billing and payment processes,

meter reading, customer reading, customer inquiry, and account maintenance.


4

data used by PG&E in this GCAP “represented nearly 67,000 new gas service 1

connections (1,600 non-residential and 65,000 residential new connections).”369 2

PG&E states this new approach improves the accuracy over the previous approach 3

that used engineering costs based on historical service length and typical regulators 4

and meters.370 5

PG&E describes the two approaches to estimate the MCAC used by the 6

Commission, namely, (a) the New Customer Only (NCO) and (b) the Rental Method 7

(RM).371 The NCO and RM are described below. 8

PG&E describes seven steps for the NCO MCAC calculation of connection 9

equipment which ORA will not repeat here.372 In addition, PG&E describes four 10

incremental changes to improve the accuracy of its NCO methodology as well as 11

adjustments to the gas MCAC model to adopt a number of improvements to the 12

electric MCAC model presented in PG&E’s 2014 and 2017 GRC Phase II.373 13

The marginal additional costs associated with the SRM are calculated as 14

loading factors (O&M loaders, A&G, General Plant, etc.) which represent the direct 15

and indirect expenses associated with the capital-related cost of investment.374 In 16

this GCAP, PG&E’s MCAC NCO methodology has improved upon the input data 17

and models for the portion on marginal ongoing Revenue Cycle Services (RCS), 18

which represent costs for billing and payment processing, meter reading, customer 19

inquiry, and account maintenance.375 Marginal customer-related costs vary with the 20

number of customers in a given customer class and not with peak demand or usage. 21

The Rental method reflects the annualized capital cost of new hook-ups, and 22

together with direct O&M and O&M loader costs per customer per year, as well as 23

the ongoing RCS, that value determines the marginal customer costs when 24

369

Appendix A, PG&E GCAP Testimony in A.17-09-006 (Revised for Errata), p. A-10.


371 Id.

372 Id., pp. A-12 through A-15.

373 Appendix A, PG&E GCAP Testimony in A.17-09-006 (Revised for Errata), pp. A-14 through A-16.

374 Appendix A, PG&E 2018 GCAP testimony, p. A-2.

375 Appendix A, PG&E 2018 GCAP testimony, p. A-1.

5

multiplied by the total number of customers for each class. In other words, the 1

Rental method treats every customer as a new customer and all customers pay an 2

annual rental fee based on the marginal unit cost of a new customer to gain access 3

to the system 4

The NCO method assumes that SRM facilities for existing customers once 5

invested and installed are sunk, and therefore irrelevant under the marginal cost 6

framework. Under the NCO, only the investment on SRM for new customers is 7

considered part of marginal customer capital cost. 8

The equipment upstream of the SRM is reflected in the appropriate 9

transportation function, in this case, the Applicants’ gas distribution system as 10

described below. 11

(B) Distribution Demand-Related Marginal Costs 12

Since marginal cost is the additional cost a utility will incur to meet new 13

demand for its services, one can say that new demand (i.e., load growth) could arise 14

either from throughput changes or changes in the number of customers. The 15

distribution facilities are considered distribution demand-related while the customer 16

facilities that provide customer access to the utilities’ gas system are considered 17

customer-related.376 The distribution-related marginal costs consist of PG&E’s gas 18

distribution marginal cost of investment capital, the marginal direct O&M, and the 19

O&M-related loader costs that are incurred for each unit of the marginal demand 20

measure. As mentioned earlier, for purposes of PG&E’s gas distribution, the 21

marginal demand measures are expressed in terms of the CWD peak day 22

demand.377 In the LRMC cost allocation model based on the NERA Regression, 15 23

years of cumulative investment is regressed against cumulative incremental load. 24

The coefficient derived from the regression represents the capital-related portion of 25

gas distribution marginal costs. 26

376

D.92-12-058, Findings of Fact #41 and #46.

377 See D.92-12-058 where the term Marginal Demand Measure (MDM) was first adopted to refer to

the criterion that causes a utility to need more capacity.

6

To arrive at fully-loaded marginal distribution capacity costs, the coefficient 1

from the regression is coupled with O&M, Administrative and General (A&G), 2

Materials and Services (M&S), and General Plant (GP) costs. This is necessary 3

because load-growth related capital additions require additional direct O&M as well 4

as O&M loaders as discussed below in other marginal costs associated with the 5

capital investment. 6

The Real Economic Carrying Cost (RECC) is used to convert capital 7

investments into annualized capital costs. It represents a series of level annual 8

revenue requirement for depreciation, property taxes, state and federal taxes, and 9

returns in constant dollars over the service life of an investment, adjusted for inflation 10

and discounted at the Applicant’s cost of capital.378 11

The use of the RECC to annualize capital costs for plant investments 12

indicates that the LRMC methodology already takes care of plant replacement. The 13

RECC contains depreciation charges for the plant investment that could be 14

considered “used up,” and therefore, the RECC has already accounted for the need 15

for replacement.379 Based on this reasoning, adding in a separate and explicit 16

adjustment for distribution replacement costs could double count these costs.380 17

The Commission previously adopted the inclusion of a replacement cost adder,381 18

but reversed its policy when it agreed with PG&E on this point in its 2005 BCAP 19

decision in D.05-06-029.382 This is reflected in the Commission’s statement in its 20

Findings of Fact in the 2005 decision in the Pacific Gas & Electric Company’s 21

(“PG&E’s”) Biennial Cost Allocation Proceeding (BCAP) in D.05-06-029:383 22

Economic literature does not resolve whether replacement costs are 23 appropriately included in long run marginal cost calculations. 24

378

D.92-12-058, p. 32.

379 Parties such as PG&E argued along this line in its 2005 BCAP in A.04-07-044 and so did

SoCalGas/SDG&E in its 2009 BCAP in A.08-02-001 (See Allison Smith Prepared Testimony in A.08-02-001, p. 4).

380 D.05-06-029.

381 D.95-12-053, p. 22 and D.97-04-082, p. 48.

382 D.05-06-029, Finding of Fact #15.

383 D.05-06-029, Finding of Fact #14.

7

1 In the text of the decision, the Commission explains:384 2 3 Moreover, although the economic literature may not explicitly address 4 this point, including replacement costs as an element of marginal costs 5 is conceptually inconsistent with economic theory. Once a utility 6 makes an investment in new facilities to serve increasing customer 7 demand, the utility will repair or replace those facilities without regard 8 for incremental increases in demand. For these reasons, we eliminate 9 the replacement cost adder from the equation used to calculate 10 marginal customer costs. 11 12 With respect to the derivation of marginal distribution-related cost 13

based on regression, the analysis regresses the combined PG&E 10-year 14

historical investments for gas distribution plant additions and 5-year forecast 15

gas distribution investment plant additions against PG&E’s combined 10-16

years historical gas distribution demand and 5-years of forecast demand.385 17

The analysis for this 15-year period generates the resulting relationship 18

between investment and load growth that determines the dollars of 19

incremental investment per decatherm of cold peak day demand. The 20

Commission described this methodology to develop the marginal unit cost for 21

distribution:386 22

a model developed by NERA to obtain a marginal unit capital cost by 23 regressing the cumulative changes in investment with cumulative 24 changes in load. Parties used a combination of historical and forecast 25 period data. 26 27

This regression process results in the coefficient used to develop an 28

estimate of the Marginal Distribution Capacity Cost. 29

384

D.05-06-029, p. 20.

385 D.92-12-058, Conclusion of Law #3, where the National Economic Research Associates (“NERA”)

regression method was adopted to calculate the marginal capital costs for distribution.

386 D.92-12-058, p. 32.

8

a. Direct O&M and Other O&M Marginal Costs 1 Associated with the Capital Investment 2

As demand and the number of customers grow, capital investments and 3

operations-related expenses are incurred to meet that growth and are the major 4

components of the utilities’ gas distribution marginal costs. However, as the costs of 5

capital investment and direct O&M expenses are incurred, they also cause other 6

cost components to increase. Marginal O&M expenses could be fixed costs in 7

nature, variable in nature, or be a mix of both since costs may occur on a regular 8

basis or be unpredictable and vary with output-related and/or customer-related 9

service activities. The other O&M cost components are A&G, general plant, 10

materials and supplies, also sometimes referred to as marginal cost O&M loaders. 11

The estimates of the direct O&M and other O&M components could be different from 12

those provided by the Applicant. However, in this case, ORA did not change the 13

Applicant’s estimates. 14

b. Scaling Marginal Cost Revenues and Cost 15 Allocation 16

To obtain the marginal cost revenues, the distribution marginal cost estimate 17

is multiplied by the allocator, in this case the MDMs, to yield the marginal cost 18

revenues for gas distribution. Until an EPMC scaling factor is applied, these 19

marginal cost revenues are considered “unscaled” marginal cost revenues and will 20

need to be scaled to reconcile with the revenue requirement.387 21

To calculate the EPMC scalar, the ratio of target scaled marginal cost 22

revenues to the base margin revenue requirement for PG&E is determined. ORA’s 23

recommendation to use the DTIM-based MDCC for distribution capacity costs and 24

the MCAC NCO method to develop the marginal customer costs results in an EPMC 25

scalar of 0.86041, that is different from that of the Applicant.388 ORA’s marginal cost 26

387

EPMC by totals was found appropriate for natural gas ratemaking in Finding of Fact # 58 and Conclusion of Law # 19, D.92-12-058.

388 Refer to ORA’s GCAP Workpapers in the Excel file for the PG&E RD Model 02152018 at Tab

“Distr_andCust_MCR” at cell C60.

9

revenue results reflect the use of a throughput forecast that is different from PG&E’s, 1

but the customer forecast is not different from those used by PG&E.389 2

Once the scaled LRMC marginal cost revenues for gas distribution are 3

obtained, then these become the basis of the revenue allocation that is used in the 4

PG&E rate design model.390 While marginal cost principles are the starting point of 5

cost allocation, the ultimate revenue allocation should also reflect equity and other 6

equally important considerations. Among those considerations are rate stability, the 7

avoidance of harsh bill impacts where reasonably possible, and the need for 8

customer understanding and acceptance of rate structures.391

9

The section on PG&E’s Rate Design proposals presents the different rate 10

outcome of the Applicant’s rate design proposals layered on top of the cost 11

allocation proposals and ORA’s recommendations. Consistent with ORA’s statutory 12

mission, the overall goal here is to obtain the lowest possible rate for service 13

consistent with reliable and safe service levels.392 Where ORA saw unusually high 14

allocations that could result in excessive bill impacts, ORA made an appropriate 15

adjustment with the use of caps on the amount of revenue allocation. This was done 16

in the case of Small Commercial customers where the prospective revenue 17

allocation indicates excess allocation compared to the historical allocation to the 18

customer class based on marginal cost. The adjusted revenue allocation to the 19

Small Commercial class was capped at the same final allocation under PG&E’s 20

Embedded Cost proposal, which was approximately at 17.72%. The excess 21

allocation above 17.72% was adjusted to the Residential customer class. 22

In addition, while obtaining the lowest possible rate, another goal is to have 23

just and reasonable rates.393 There are other important goals of ratemaking such as 24

rates based on cost-causation principles where customer cost responsibility is 25

389

See Ex. ORA-02 by T. Renaghan regarding ORA’s recommendations on the forecast throughput and forecast number of gas customers.

390 PGE RD Model 2018 GCAP 02152018.

391 D.92-06-020, Conclusion of Law #2.

392 Public Utilities Code § 309.5.

393 Public Utilities Code § 451.

10

aligned with the proposed rate structure. Rates should encourage economically 1

efficient decision making by reflecting the marginal cost pricing signals. There are 2

also several attributes of a sound rate structure. Professor James Bonbright, one of 3

the foremost experts in public utility ratemaking, identified at least ten attributes of a 4

sound rate structure.394 Among these attributes are that rates should be sufficient to 5

provide for the utilities’ authorized revenue requirements.395 Rates should be stable, 6

predictable, be easily understandable, be non-controversial and avoid rate shock to 7

customers.396 Rates should encourage conservation and energy efficiency.397 The 8

rates should maintain consistency with existing practices to the extent possible.398 9

Through the years in cost allocation and rate design proceedings, the Commission 10

has adhered to these attributes of a sound rate structure in its ratemaking. These 11

“Bonbright principles” of rate design are reflected in the Commission’s decisions in 12

D.15-07-001 and D.08-07-045.399

13

c. Main Differences Between Marginal and Embedded 14 Costs 15

In a discovery response, PG&E provided the following description of the main 16

differences between marginal and embedded cost methods:400 17

Marginal Cost method involves the following steps: (1) 18 Functionalization of costs, (2) Calculation of Marginal Costs for all 19 functions, (3) Calculation of function specific EPMC (there will be one 20 EPMC (Equal Percentage of Costs Multiplier) for a cost function) and 21 (4) RRQ (Revenue Requirement) allocation by function and by 22 customer class, (5) Total RRQ allocation by summing up the function 23 RRQs for each customer class. 24 25

394

Bonbright, J., Danielsen, A., and Kamerschen, D., 2nd

Ed. 1988. Principles of Public Utility Rates, Public Utilities Reports, Inc.

395 Id., pp. 383-384.

396 Id.

397 Id.

398 Id.

399 The Commission references the “Bonbright principles” in D.15-07-001, pp. 27-28.

400 PG&E Response to data request ORA-04 Q.1(a).

11

Embedded cost method involves the following steps: (1) 1 Functionalization of costs, (2) Identification of cost drivers for each 2 cost function, (3) Determination of unit costs for the cost drivers, (4) 3 RRQ allocation by function and by customer class (5) Total RRQ 4 allocation by summing up the function RRQs for each customer class. 5 6 Marginal cost based methodology for gas distribution costs allocation 7 involves calculation of (1) Marginal Distribution Capacity Cost (MDCC) 8 and (2) Marginal Customer Access Cost (MCAC) based on either 9 Rental method or New Customer Only (NCO) method. Marginal costs, 10 when multiplied by the corresponding marginal cost drivers at portfolio 11 level, results in total marginal cost revenue. Total Marginal Cost 12 Revenue (MCR) is not equal to the total RRQ, i.e., the total cost 13 incurred; MCR is 14 usually less than the RRQ. Hence, EPMC, which is the ratio of the 15 total RRQ to the total MCR, is used to determine the allocated costs 16 by customer class. MCR of each customer class is calculated, and 17 then multiplied by the portfolio level EPMC to determine the allocated 18 cost. 19 20 Embedded cost methodology for gas distribution costs allocation 21 involves obtaining costs data from 2017 GRC Phase I, by functions 22 (1) Line, (2) Service, Regulator and Meter (SRM) and (3) Revenue 23 Cycle Services (RCS). Costs drivers for Line, SRM and RCS are 24 determined. For line cost, the cost driver is the Cold Winter day 25 throughput of the most recent average temperature year. For SRM 26 costs, cost driver is number of Meter plus Module, and for RCS, the 27 cost drivers are several based on different types of services and sub-28 services provided, and have been described in PG&E’s response to 29 ORA Data Request 2, Question 3 (a). Revenue allocation of Line, 30 SRM and RCS costs are then done by using the cost drivers. 31 32 For both marginal cost and embedded cost-based allocations, PG&E 33 performs two adjustments in its gas rate design model in order to 34 calculate the final allocations across customer classes. PG&E scales 35 either the embedded cost or marginal cost based allocations, 36 depending on which is being used in the scenario, to total to the 37 authorized gas base distribution revenue requirement net of the NGV2 38 compression cost and net of Franchise Fees and Uncollectible 39 Expense. PG&E’s gas rate design model then allocates i) the 40 proposed NGV2 compression cost to the NGV2 class, ii) Franchise 41 Fees separately across all customer classes, and iii) Uncollectibles 42 Expense to all classes except PG&E’s wholesale customers. The 43 resulting totals by customer class are the final proposed allocations. 44 As described in previous data responses and PG&E’s Chapter 6 45 testimony, these adjustments, while necessary, are minor and on the 46

12

order of less than $5 million typically with a net zero change in the 1 total revenue requirement.2

APPENDIX B

WITNESS QUALIFICATIONS

12

STATEMENT OF QUALIFICATIONS 1

PEARLIE SABINO 2

Q.1: Please state your name and address. 3

A.1: My name is Pearlie Sabino. My business address is 505 Van Ness Avenue, 4

San Francisco, California, 94102. 5

Q.2: By whom are you employed and in what capacity? 6

A.2: I am employed by the Office of Ratepayer Advocates as a Public Utilities 7

Regulatory Analyst V in the Energy Cost of Service and Natural Gas Branch. 8

Q.3: Briefly describe your educational background and work experience. 9

A.3: I have a Bachelor of Science in Business Economics from the University of 10

the Philippines and a Master of Arts in Economics from the Ateneo de Manila 11

University. As a United States Agency for International Development (USAID) 12

scholar, I obtained Executive training on Energy Planning and Policy from the 13

University of Pennsylvania. 14

Prior to joining ORA, I worked in various positions from Research Analyst to 15

Corporate Planning Analyst to Chief Economist with the National Power Corporation 16

(Philippines). 17

Since joining the ORA in 1997, I have worked on a number of electric and gas 18

rate cases, including but not limited to: the review of SoCalGas’ Gas Cost Incentive 19

Mechanism; the review of Biennial Cost Allocation Proceeding (BCAP) applications 20

for PG&E, SoCalGas, and SDG&E; various gas transportation contracts (such as 21

Guardian, Ruby, US Gypsum); various applications pertaining to the grant of 22

Certificate of Public Convenience and Necessity (CPCN) for gas storage contracts, 23

including amendments; SoCalGas/SDG&E System Integration (SI) and Firm Access 24

Rights (FAR) proceedings, including the FAR Update proceeding, the Joint 25

SCE/SoCalGas/SDG&E Omnibus proceeding, the Joint PG&E/SoCalGas/SDG&E 26

Application for Public Purpose Program (PPP) Cost Reallocation proceeding, the 27

PG&E BCAP in 2005 and 2009, the SoCalGas SDG&E BCAP in 2009, the PG&E 28

Gas Transmission & Storage (GT&S) rate cases in A.13-12-012 and A.09-09-013 29

(Gas Accord V Settlement), the PG&E Pipeline Safety Enhancement Plan (PSEP) 30

Phase 1 in R.11-02-019 and San Bruno Investigation cases, the SoCalGas/SDG&E 31

13

Pipeline Safety Enhancement Plan (PSEP) in A.11-11-002 Phase 1 &2, the 1

Southwest Gas 2014 GRC in A.12-12-024, the SoCalGas/SDG&E North-South 2

Project in A.13-12-013, the Liberty GRC in A.15-05-008, the SoCalGas/SDG&E 3

Triennial Cost Allocation Proceeding (TCAP) in A.15-07-014, the SoCalGas/SDG&E 4

Phase 1 Issues in A.15-09-013 (Line 1600/Line 3602), the Joint Wild Goose/Lodi 5

Request for Encumbrance of Assets in A.17-01-024, and the SoCalGas Customer 6

Incentive Program (CIP) in A.16-12-010. 7

Q.4: What is your area of responsibility in this proceeding? 8

A.4: I am responsible for ORA’s testimony in this proceeding regarding the 9

Scoping Memo issues 3, 4, 5, 6, 7, and 13 in PG&E’s GCAP. I am sponsoring all of 10

Ex. ORA-05 with the exception of the portion in Section III.B.2(f) sponsored by Mark 11

Pocta. 12

Q.5: Does that complete your prepared testimony? 13

A.5: Yes, it does. 14

14

STATEMENT OF QUALIFICATIONS 1

ROBERT MARK POCTA 2

My name is Robert Mark Pocta. My business address is 505 Van Ness 3

Avenue, San Francisco, California, 94102. I am employed by the California Public 4

Utilities Commission as a Program Manager in the Office of Ratepayer Advocates 5

(ORA) Energy Cost of Service and Natural Gas Branch (ECOS/NG). 6

I graduated from Purdue University in May 1979, with a Bachelor of Science 7

degree in Civil Engineering. In 1982, I became registered as a Professional Civil 8

Engineer in the State of California. 9

I was employed by the California Department of Transportation from June 10

1979 to October 1980. In November 1980, I transferred to the Commission and 11

worked in the Water Branch of the Public Staff Division until December 1984. My 12

responsibilities included preparing estimates of revenues, expenses, taxes and rate 13

base in numerous rate case applications of Class A water utilities. From January 14

1985 to August 1986, I worked in the Energy Operational Costs Branch on a number 15

of energy-related rate applications. 16

I began to work in the Fuels Branch in September 1986 and served as a 17

Program and Project Supervisor beginning in 1988. I served in various capacities as 18

both a witness on technical and policy issues and as a project manager in regulatory 19

proceedings. These proceedings included natural gas industry investigations, 20

rulemakings and restructuring, natural gas policy, utility mergers, incentive 21

regulation, cost allocation, reasonableness reviews, capacity brokering, need for 22

new interstate pipelines, natural gas vehicles, and natural gas procurement. I have 23

testified as an expert witness many times before the Commission in various 24

proceedings and have testified before the California Energy Commission. I have 25

submitted prepared testimony and appeared as an expert witness on behalf of the 26

Commission at the Federal Energy Regulatory Commission in proceedings involving 27

interstate gas pipeline companies. 28

My current administrative responsibilities include overall program planning, 29

managing the work of the ECOS/NG Branch Supervisors and their staff, overseeing 30

the production of various reports on utility General Rate Case (GRC) and natural gas 31

15

proceedings, controlling the quality of work performed by the Branch, developing 1

policy on GRC, cost of service and natural gas matters, and coordinating the branch 2

work with other ORA branches. I have been responsible for managing all GRC 3

proceedings filed at the Commission for the last fifteen years. I have represented 4

ORA in various settlement negotiations, including the Pacific Gas and Electric 5

Company’s 2003, 2007, 2011, and 2017 GRCs, the Sempra Utilities 2004, 2008, 6

and 2016 GRCs, PG&E Gas Accord proceedings, PacifiCorp GRCs, Liberty Utilities 7

GRCs, Southwest Gas’ 2009 and 2014 GRCs, the Comprehensive Gas OII 8

Settlement Agreement for Southern California Gas Company (SoCalGas) and San 9

Diego Gas & Electric Company (SDG&E), the SoCalGas “Global Settlement” and 10

settlements of cost allocation proceedings. I have coordinated ORA’s participation in 11

the development and modifications of gas procurement incentive mechanisms for 12

SoCalGas and PG&E. 13

I am responsible for Exhibit ORA-05, Section III, B.2 (f). 14

This concludes my statement of qualifications. 15

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