Rebuttal Testimony of Catherine E. Yap On Behalf of ...

Application No. 18-07-024

Exhibit No. ____________

Witness: Catherine E. Yap

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

Application of SOUTHERN CALIFORNIA GAS COMPANY (U904G) and SAN DIEGO GAS & ELECTRIC COMPANY (U902G) for authority to revise their natural gas rates and implement storage proposals effective January 1, 2020 in this Triennial Cost Allocation Proceeding.

Application 18-07-024 (Filed July 31, 2018)

Rebuttal Testimony of Catherine E. Yap

On Behalf of

Southern California Generation Coalition

May 10, 2019

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TABLE OF CONTENTS

1 Introduction 1

2 The Commission Should Reject TURN’s Proposal to Escalate 2016 Embedded

Costs Using Percentage Escalation Factors that Will Introduce Error into the

Embedded Cost Study. 1

3 The Commission Should Reject Witness Florio’s Proposal to Set System-Wide

Storage Inventory Capacity at 119.5 Bcf. 2 3.1 Witness Florio’s Assumption that Total System Storage Inventory Capacity

Will Be 119.5 Bcf During the TCAP Period Is Purely Speculative. 2 3.2 Witness Florio’s Reasoning Is Flawed. 3 3.3 The Amount of Inventory Capacity Assumed to Be Available at Aliso Canyon

Should Be Set Realistically Because It Drives the Availability of Storage

Services. 5

4 The Commission Should Deny TURN’s Proposal that Core Ratepayers Not Be

Required to Pay for Load Balancing Inventory or Withdrawal Costs. 7 4.1 Unless the Commission Directs that Aliso Canyon Inventory Be Increased to

68.6 Bcf and the Aliso Canyon Withdrawal Protocol Is Lifted, the Core Will

Not Have Access to the Level of Storage Inventory Capacity that TURN

Assumes It Will Have. 7 4.2 Unless the Commission Specifically Directs that Aliso Canyon Inventory Be

Increased to 68.6 Bcf and the Aliso Canyon Withdrawal Protocol Is Eliminated,

the Core Will Not Be Able to Rely on Its Withdrawal Capacity If Storage

Inventory Falls Significantly Below Maximum Inventory Levels. 9 4.3 Because the Core Balances to Forecasted Usage Rather than Actual Usage, the

System Operator Is Required to Balance to Compensate for Core Forecast

Error Using Load Balancing Resources and the Core Should Be Required to

Pay for the Load Balancing Resources Needed by the System Operator to

Balance the System to Compensate for Core Forecasting Error. 10

5 The Commission Should Reject TURN’s Recommendation that Core Injection

Capacity Reservation Should Be Based on Ratable Injections over the

Summer Season. 12

6 The Commission Should Reject TURN’s Proposal to Functionalize Capital-

Related Revenue Requirement Based on Utility Plant Less Asset Retirement

Obligations. 14

7 The Commission Should Adopt TURN’s Proposal to Assign All Compressor

Station O&M to Backbone Transmission. 16

8 TURN’s Evaluation of Marginal Customer Cost Methodologies Is Flawed. 17

9 The Commission Should Permanently Approve the Current Language in Rule

30 that Allows for the Trading of Scheduled Quantities on OFO Days. 19

10 The Commission Should Permanently Approve the Limited Provisions in Rule

30 that Allow SoCalGas to Waive OFO Noncompliance Charges. 21

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Attachment A: 2018 California Gas Report, excerpts.

Attachment B: 2018 California Gas Report, SoCalGas Workpapers, excerpts.

Attachment C: A.17-10-007, Applicants’ Response to SCGC-04, excerpts.

Attachment D: SoCalGas Envoy Notices regarding Southern System Capacity.

Attachment E: SoCalGas Envoy Maintenance Notice, October 1, 2018

Attachment F: SoCalGas Schedule G-BTS, excerpt.

Attachment G: A.18-06-009, SoCalGas GCIM Year 24, Public Advocates Office Monitoring and

Evaluation Report, November 8, 2018, excerpts

Attachment H: FERC Docket No. RM02-7-000, Order No. 631, April 9, 2003, excerpts

Attachment I: Fung 2020 TCAP Final Workpapers, excerpts.

Attachment J: California’s Low Homeownership Rate to Continue, March 28, 2019,

https://journal.firsttuesday.us/californias-rate-of-homeownership-2/30161/

Attachment K: SoCalGas Rule 30, excerpt.

Attachment L: 2017 Customer Forum Presentation, May 8, 2017, excerpts.

Attachment M: 2018 Customer Forum Presentation, May 9, 2018, excerpts.

Attachment N: 2019 Customer Forum Presentation, May 7, 2019, excerpts.

Attachment O: SoCalGas Envoy Maintenance Update, May 3, 2019.

Attachment P: A.17-10-002, Applicants’ Response to SCGC-IS-04, excerpts

Attachment Q: Figure 1 data

Attachment R: Applicants’ Response to TURN-04, excerpt

Attachment S: A.17-10-002, Direct Testimony of Sharim Chaudhury, excerpt

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1 2

Rebuttal Testimony of Catherine E. Yap 3 On Behalf of 4

Southern California Generation Coalition 5

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1 Introduction 7

This testimony responds to statements made in the following opening testimonies on 8

ratemaking issues that were served on March 11, 2016, in this proceeding: 9

Testimony of Michel Florio (“Florio Direct”) on behalf of The Utility Reform Network 10

(“TURN”), 11

Testimony of William Marcus (“Marcus Direct”) on behalf of TURN, and 12

Testimony of Maurice Brubaker (“Brubaker Direct”) on behalf of Indicated Shippers. 13

The opening testimonies addressed issues raised by the July 31, 2018, direct testimony by 14

Southern California Gas Company (“SoCalGas”) and San Diego Gas and Electric Company 15

(“SDG&E”) (jointly, “Applicants”). This testimony is presented by Catherine E. Yap on behalf 16

of the Southern California Generation Coalition (“SCGC”). Ms. Yap has more than three 17

decades of experience preparing and delivering testimony before this Commission as well as in 18

other jurisdictions. Ms. Yap’s statement of qualification is included as Attachment A to her 19

direct testimony, dated April 12, 2019. 20

2 The Commission Should Reject TURN’s Proposal to Escalate 2016 Embedded Costs 21 Using Percentage Escalation Factors that Will Introduce Error into the Embedded 22 Cost Study. 23

TURN witness Florio complains that a mismatch is created by SoCalGas allocating 24

transmission and storage costs using 2016 embedded costs while allocating customer and 25

distribution costs using long-run marginal costs that are based on 2016 actual costs scaled up to 26

meet the 2020 revenue requirement.1 To address this issue, witness Florio recommends that the 27

Commission base the cost allocation in this proceeding on a forecast of transmission and storage 28

1 Florio Direct at 9.

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revenue requirement “achieved by escalating the ultimately adopted 2016 embedded costs for 1

transmission and storage (preferably those proposed by TURN witness Marcus) by 3.5% for each 2

attrition year (2017 and 2018), plus an additional uniform percentage change to reflect whatever 3

revenue requirement is ultimately adopted in the GRC for the 2019.”2 In essence, TURN 4

recommends that the company perform an embedded cost allocation that is based on pseudo-5

recorded costs. 6

TURN’s recommendation is improper. Embedded costs are recorded costs, so an 7

embedded cost study should be based on recorded costs. Using percentage escalation factors to 8

escalate recorded costs would artificially alter the results of the embedded cost study and 9

introduce error into the study. The Commission should reject witness Florio’s proposal which 10

would introduce error into the embedded cost study. 11

3 The Commission Should Reject Witness Florio’s Proposal to Set System-Wide 12 Storage Inventory Capacity at 119.5 Bcf. 13

The Commission should reject witness Florio’s proposal to set system-wide inventory 14

capacity at 119.5 Bcf unless the Commission approves use of the 68.6 Bcf Aliso Canyon storage 15

inventory capacity and terminates the Aliso Canyon Withdrawal Protocol by the time the TCAP 16

rates go into effect. 17

3.1 Witness Florio’s Assumption that Total System Storage Inventory Capacity Will Be 18 119.5 Bcf During the TCAP Period Is Purely Speculative. 19

TURN witness Florio assumes that the Commission will allow the Applicants to increase 20

the use of Aliso Canyon storage inventory capacity from 34 Bcf to 68.6 Bcf, resulting in total 21

system-wide storage capacity of 119.5 Bcf, and he assumes the Commission will terminate the 22

restriction that the Aliso Canyon Withdrawal Protocol places on SoCalGas’s operation of Aliso 23

Canyon. 3 However, he admits that “it is not entirely clear if or when Aliso Canyon will be 24

allowed to resume full operations.” 4 25

2 Id.at 11. 3 Id. at 13. The Aliso Canyon Withdrawal Protocol is attached as Attachment AC to my Direct Testimony. 4 Id. at 13.

3

Witness Florio presents no evidence to support his assumptions. His assumptions are 1

purely speculative. Unless the Commission approves use of the full 68.6 Bcf of Aliso Canyon 2

storage inventory and terminates the Aliso Canyon Withdrawal Protocol by the time the TCAP 3

rates go into effect, the Commission should reject witness Florio’s proposal that the Commission 4

allocate costs in this proceeding on the basis of a working gas inventory capacity that cannot be 5

filled with working gas. 6

3.2 Witness Florio’s Reasoning Is Flawed. 7

In addition to being speculative, witness Florio’s argument for assuming the full 8

availability of Aliso Canyon inventory is flawed. Witness Florio argues: 9

If the restrictions are not lifted, less storage capacity will be 10 available, but there is no mechanism within the scope of this TCAP 11 to adjust the revenue requirement to reflect that. Any cost 12 disallowances related to the situation at Aliso Canyon will be 13 decided in the Aliso Investigation docket, I.17-02-002. Rather than 14 charging storage customers higher rates now in anticipation of 15 Aliso’s not being fully available, I think it makes more sense to set 16 rates assuming full availability and then provide appropriate 17 refunds later if the Commission determines that the revenue 18 requirement should be adjusted downward.5 19

Each of the sentences in witness Florio’s argument is incorrect. 20

In his first sentence, witness Florio contends, “If the restrictions are not lifted, less 21

storage capacity will be available, but there is no mechanism within the scope of this TCAP to 22

adjust the revenue requirement to reflect that.” Witness Florio errs in implying that there should 23

be any change in revenue requirement if the Commission decides that the amount of system-wide 24

storage inventory capacity that should be used to allocate costs in this TCAP is less than his 25

proposed 119.5 Bcf. This is a TCAP, not a reasonableness review or a general rate case. 26

Assuming the amount of system-wide inventory capacity that results from 68.6 Bcf at Aliso 27

Canyon or assuming the lower amount of inventory capacity that can be used currently, 34 Bcf, 28

5 Id. at 13.

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affects the allocation of storage capacity costs but does not address the level of revenue 1

requirement that is to be recovered through rates set in this proceeding as witness Florio implies. 2

In this TCAP, the functionalized storage embedded costs will be allocated over the 3

inventory, withdrawal, and injection capacities that the Commission adopts in this proceeding. 4

The amounts of inventory capacity and corresponding withdrawal and injection capacity should 5

be set on the basis of the amount of capacity that can actually be used at Aliso Canyon as I 6

recommended in my Direct Testimony6 without making any speculative assumptions about 7

Commission actions in the future. 8

In his second sentence, witness Florio jumps from discussing the TCAP to incorrectly 9

asserting that another proceeding, I.17-02-002, includes within its scope “cost disallowances 10

related to the situation at Aliso Canyon.” Witness Florio is mistaken about the scope of I.17-02-11

002, as demonstrated by the Scoping Memo, which poses two questions establishing the scope of 12

the proceeding: 13

1) Is it feasible to reduce or eliminate the use of the Aliso Canyon 14 Natural Gas Storage Facility while still maintaining electric and 15 energy reliability for the region? 16

2) Given the outcome of Question 1, should the Commission 17 reduce or eliminate the use of the Aliso Canyon Natural Gas 18 Storage Facility, and if so, under what parameters?7 19

The Scoping Memo makes no mention of “cost disallowances,” nor does it express intent to 20

review ratemaking regarding the facility. In any event, disallowances related to Aliso Canyon 21

are not in the scope of the current proceeding. The Commission should not allocate costs in this 22

TCAP making assumptions about whether or not there should be any disallowances in the Aliso 23

Canyon revenue requirement. 24

6 Direct Testimony of Catherine Yap (“Yap Direct”) at 3-4. 7 I.17-02-002, Scoping Memo and Ruling of Assigned Commission and Administrative Law Judge, June 20,

2017, at 7. The Phase 2 Scoping Memo contains a similar, albeit more detailed, characterization of the proceeding. See, I.17-02-002, Scoping Memo and Ruling of Assigned Commission and Administrative Law Judge, March 29, 2019, at 2.

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In his third sentence, witness Florio says he thinks it “makes more sense to set rates 1

assuming full availability and then provide appropriate refunds later” if the Commission makes 2

changes to revenue requirement. I disagree. First, as discussed previously, refunds are not in the 3

scope of this proceeding, and costs should not be allocated assuming that there will be refunds. 4

Second, the amounts of storage inventory, injection, and withdrawal capacities that are available 5

for purposes of this TCAP will determine the amount and type of storage services that are 6

available. Assuming “full availability” of Aliso Canyon inventory capacity of 68.6 Bcf would 7

result in an assumption of more injection and withdrawal capacity than if the actually available 8

34 Bcf were assumed to be available at Aliso Canyon. More inventory, injection, and 9

withdrawal capacities would be allocated among storage services such as core reliability and 10

load balancing services even though the inventory, injection, and withdrawal capacities are 11

purely hypothetical. The storage embedded costs would then be allocated among the storage 12

services based on these hypothetical amounts of services, which, in turn, would be allocated to 13

customer classes based on what storage services they hypothetically would be expected to utilize. 14

However, given that SoCalGas can only provide storage services using inventory, injection, and 15

withdrawal capacities that are actually available with Aliso Canyon limited to 34 Bcf, basing the 16

allocation of storage costs on hypothetical storage capacity cannot result in a reasonable 17

allocation of storage costs. 18

3.3 The Amount of Inventory Capacity Assumed to Be Available at Aliso Canyon Should 19 Be Set Realistically Because It Drives the Availability of Storage Services. 20

If rates were set assuming the availability of the hypothetical 68.6 Bcf of inventory 21

capacity at Aliso Canyon, which results in the Applicants’ proposed 119.5 Bcf of inventory 22

capacity instead of the 84.9 Bcf that corresponds to current operations,8 rates would be set based 23

on a phantom 34.6 Bcf of inventory capacity that is, in fact, unavailable for service to customers. 24

Under the Applicants’ proposed 119.5 Bcf scenario, the 34.6 Bcf of phantom inventory capacity 25

would supposedly provide 8 Bcf of additional inventory capacity for load balancing services, 21 26

8 119.5 Bcf – 34.6 Bcf = 84.9 Bcf

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Bcf of cushion gas9 intended to support increased withdrawal capacity, and 5.6 Bcf of additional 1

inventory capacity for core reliability services. The 119.5 Bcf scenario also assumes an 2

additional 1240 MMcf/d of year around withdrawal capacity that is actually unavailable for 3

service to customers outside of the peak winter months. 4

As I demonstrated in my direct testimony, if the Commission does not allow the 5

increased inventory capacity from 34 Bcf to 68.6 Bcf at Aliso Canyon along with cessation of 6

the Aliso Canyon Withdrawal Protocol, SoCalGas will not be able to provide storage services to 7

the extent they proposed in their application.10 The resulting allocation of storage costs is 8

extremely different than the picture portrayed by the Applicants in their proposals.11 9

Furthermore, the operation of the Applicants’ transmission and storage system will 10

continue to rely upon the interruption of electric generators in order to maintain services to the 11

core and other customer classes during very cold weather.12 Under TURN’s proposal, unless the 12

Commission allows the increased inventory capacity at Aliso Canyon and removes the Aliso 13

Canyon Withdrawal Protocol, electric ratepayers will be unduly burdened by increased costs 14

when electric generators pass along high gas costs while at the same time seeing winter time 15

costs increased when electric generators have their gas service interrupted and are required to 16

substitute more costly electricity supply alternatives.13 17

A better approach than the one proposed by witness Florio would be to assume a storage 18

inventory of 34 Bcf in Aliso Canyon unless the Commission issues an order authorizing a 19

storage inventory of 68.6 Bcf at that field by the time the Commission reaches a decision in this 20

proceeding.14 In addition, the Aliso Canyon Withdrawal Protocol should be assumed to be in 21

effect until it is actually lifted by Commission order. 22

9 The Applicants refer to this cushion gas as “reliability” service. 10 Yap Direct at 3. 11 Id. at 47 (Table 14). 12 Id. at 51-53. 13 Id. at 52. 14 Id. at 3.

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4 The Commission Should Deny TURN’s Proposal that Core Ratepayers Not Be 1 Required to Pay for Load Balancing Inventory or Withdrawal Costs. 2

TURN witness Florio claims that the core has no need for load balancing inventory or 3

withdrawal capacity because the core has its own storage inventory and withdrawal capacity for 4

reliability purposes.15 Given the reality of the limitations on the use of Aliso Canyon, the storage 5

inventory at Aliso Canyon is 34 Bcf not 68.6 Bcf as the Applicants and witness Florio assume. 6

Thus, the core’s reliability inventory is less than witness Florio claims, and the core’s withdrawal 7

capacity is less robust than witness Florio believes. There is far less core reliability capacity than 8

there would be available otherwise to provide core reliability service and for sharing with the 9

core’s load balancing responsibilities. As I showed in Table 13 in my Direct Testimony,16 10

instead of the current 83 Bcf17 or the 82.5 Bcf that the Applicants say the core needs for core 11

reliability service during the TCAP period,18 only 76.9 Bcf of inventory capacity would be 12

available for core reliability service, and that is assuming that only 8 Bcf of inventory capacity is 13

available for load balancing service. Finally, given the actual degree of variability between the 14

core’s usage and the core’s forecasted usage, the core ought to support the system resources 15

required to balance the system. I will address each of these points in turn. 16

4.1 Unless the Commission Directs that Aliso Canyon Inventory Be Increased to 68.6 Bcf 17 and the Aliso Canyon Withdrawal Protocol Is Lifted, the Core Will Not Have Access 18 to the Level of Storage Inventory Capacity that TURN Assumes It Will Have. 19

Witness Florio claims that core “inventory is full on at most a few days per year, at the 20

end of the summer injection season and prior to the start of winter withdrawals. Gas Acquisition 21

could readily leave a small amount of slack below its maximum inventory allocation in order to 22

accommodate any positive imbalances on the few days when core storage is close to its 23

maximum.” 24

15 Florio Direct at 23. 16 Yap Direct at 43. 17 D.16-06-039, slip op. at 32. 18 Direct Testimony of Michelle Dandridge at 8.

8

Again, witness Florio’s assumption is that Aliso Canyon is operating with a maximum 1

storage inventory 68.6 Bcf under unconstrained operating circumstances. This simply is not true. 2

In reality, Aliso Canyon is operating with a maximum capacity of 34 Bcf and is operating under 3

the Aliso Canyon Withdrawal Protocol. Thus, the actual capacity of the SoCalGas storage 4

system is 84.9 Bcf, not 119.6 Bcf as the Applicants and TURN claim. Furthermore, once 8 Bcf 5

is assigned to load balancing, the core is left with 76.9 Bcf of which 19 Bcf is needed to remain 6

in the ground during the winter months in order to help support withdrawal capacity for core 7

reliability purposes. This leaves 57.9 Bcf of core inventory, less than 70 percent of the current 8

capacity, to provide core reliability service during the winter months. 9

Finally, witness Florio does not state how much of the total cumulative customer 10

imbalance is attributable to the core, probably because the Applicants have not provided this 11

breakdown.19 However, it is reasonable to apportion the total cumulative customer imbalance 12

between core and noncore on a prorata basis reflecting their respective shares of usage. The core 13

on average represents about 40 percent of system usage but its share increases to 53 percent 14

during the winter months, December through February.20 In my direct testimony, I demonstrated 15

that the total positive cumulative customer imbalance slightly exceeded 8 Bcf on one occasion 16

and nearly equaled 8 Bcf on two other occasions.21 Witness Florio’s characterization of the need 17

as a “a small amount of slack below its maximum inventory allocation” is misguided. Forty 18

percent of 8 Bcf is 3.2 Bcf, and 53 percent of 8 Bcf is 4.2 Bcf. Neither are “small amounts.” 19

Thus, under witness Florio’s proposal, the core would further reduce its 57.9 Bcf of winter 20

inventory by 4.2 Bcf, leaving only 53.7 Bcf available to provide core reliability during the winter 21

months. 22

23

19 Attachment R: Applicants’ Response to TURN-04, Q.1.d. 20 Attachment B: 2018 California Gas Report, SoCalGas Workpapers at 13; Attachment A: 2018 California Gas

Report at 130; A.17-10-007. 21 Yap Direct at 17.

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4.2 Unless the Commission Specifically Directs that Aliso Canyon Inventory Be Increased 1 to 68.6 Bcf and the Aliso Canyon Withdrawal Protocol Is Eliminated, the Core Will 2 Not Be Able to Rely on Its Withdrawal Capacity If Storage Inventory Falls 3 Significantly Below Maximum Inventory Levels. 4

Witness Florio claims that he “requested and examined daily injection and withdrawal 5

data for the retail core since April 1, 2012, and did not find a single day on which the core used 6

its entire withdrawal reservation, which has been 2225 MMcf/day.”22 In making this statement, 7

witness Florio is presumably suggesting that the core has withdrawal capacity “left over” for 8

load balancing purposes. This simply is not true. 9

First, the 2225 MMcf per day withdrawal reservation is effectively an insurance policy 10

maintained for the core in case extraordinarily cold weather occurs. Thus, withdrawal resources 11

need to be maintained sufficiently near full capacity during the entirety of the winter for the core. 12

The need for this has been demonstrated over the last two years where the coldest weather has 13

occurred late in the winter, during February and early March, rather than in the traditional 14

coldest months of December and January. 15

Second, at the currently lower storage inventory levels of 34 Bcf in Aliso Canyon, the 21 16

Bcf of cushion gas that the Applicants have proposed to use to prop up withdrawal capacity for 17

both core reliability and load balancing purposes will not be available. Thus, as inventory 18

capacity is drawn down, withdrawal capacity will fall off. This should not be a problem for core 19

reliability during the winter months unless there are repeated periods of cold weather, but if the 20

core were to use its inventory and withdrawal capacity for load balancing purposes as proposed 21

by witness Florio, the core could end up drawing down the inventory and resulting withdrawal 22

capacity to a much greater extent than would be acceptable for reliability purposes. 23

Third, the core places burdens on system resources that remain invisible to the core but 24

are very real to the System Operator. The core is required to balance its supplies of gas to its 25

forecasted level of usage, not to its actual level of usage. However, there can be a significant 26

error in the forecast of core usage. The System Operator has to deal with what the core is 27

22 Florio Direct at 23.

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actually using even when it significantly deviates from what has been forecasted. This is the 1

subject of the next section of my testimony. 2

4.3 Because the Core Balances to Forecasted Usage Rather than Actual Usage, the 3 System Operator Is Required to Balance to Compensate for Core Forecast Error 4 Using Load Balancing Resources and the Core Should Be Required to Pay for the 5 Load Balancing Resources Needed by the System Operator to Balance the System to 6 Compensate for Core Forecasting Error. 7

The Applicants forecast that the combined retail core usage represents about 42 percent 8

of overall SoCalGas23 and SDG&E24 system usage during Test Year 2019. Ninety-nine percent 9

of core customers making up about 94 percent of core usage are served by the SoCalGas Gas 10

Acquisition Department (“Gas Acquisition”). 25,26 Gas Acquisition also purchases gas for 11

company usage, which represents about one percent of system usage.27 Thus, on average 12

throughout the year, Gas Acquisition is responsible for purchasing gas for about 40 percent of 13

system usage, making Gas Acquisition the single largest shipper on the Applicants’ integrated 14

transmission systems. However, during the winter months, December, January, and February, 15

Gas Acquisition is responsible on average for purchasing about 53 percent of system usage,28 16

and on a peak cold day, Gas Acquisition’s share of system usage would increase to about 64 17

percent.29 18

The Demand Forecasting Group within the Applicants’ Regulatory Affairs Department 19

provides daily forecasts for “the same flow day and the four upcoming flow days” to Gas 20

23 The projection is for an average temperature year. Attachment B: 2018 California Gas Report, SoCalGas

Workpapers at 13. 24 The projection is for an average temperature year. Attachment A: 2018 California Gas Report at 130. 25 The great majority of core customers receive bundled transportation and gas procurement service through

Gas Acquisition while a small remainder obtains gas procurement service from Core Transport Agents (“CTAs”). Attachment C: A.17-10-007, Applicants’ Response to SCGC-04, Q.4.1. There are 22 CTAs on SoCalGas system serving 71,137 core accounts. Attachment P: A.17-10-002, Applicants’ Response to SCGC-IS-04, Q.4.1.8 states that CTAs serve 3,502 core customers on SDG&E’s system.

26 Attachment B: 2018 California Gas Report, SoCalGas Workpapers at 13; Attachment A: 2018 California Gas Report at 130.

27 Attachment B: 2018 California Gas Report, SoCalGas Workpapers at 13. 28 Attachment B: 2018 California Gas Report, SoCalGas Workpapers at 13; Attachment A: 2018 California Gas

Report at 130; A.17-10-007, Attachment C: Applicants’ Response to SCGC-04, Q.4.1; Attachment P: Applicants’ Response to SCGC-IS-04, Q.4.1.8.

29 Attachment A: 2018 California Gas Report at 96-97.

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Acquisition.30 In turn, Gas Acquisition must balance its supply nomination against this daily 1

forecast. However, Figure 1 demonstrates that there are regular deviations between the core 2

forecast and core usage, which is not addressed by Gas Acquisition because it is only required to 3

balance to a forecast: 4

5 Figure 1 6

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In Figure 1 the positive values represent an over-forecast of core usage, and the negative 22

values represent an under-forecast of core usage. It is quite apparent from Figure 1 that the 23

percentage error in forecasting can be quite substantial even during the winter months where the 24

core’s usage is itself very large. 25

30 Attachment S: A.17-10-002, Direct Testimony of Sharim Chaudhury at 1.

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For example, in an average weather year, during the cold weather months of December 1

through February, retail core usage averages 1,414 million cubic feet of gas per day 2

(“MMcf/d”).31 If Gas Acquisition delivers too little gas during an average year winter day 3

because it is matching a forecast that contains a 20 percent error, Gas Acquisition’s under-4

delivery amounts to 283 MMcf/d32 of gas that must be made up from other sources in order to 5

balance the system. On a peak cold day, the retail core usage can increase to 3,189 MMcf/d.33 If 6

Gas Acquisition under-delivers by 20 percent on a peak winter cold day because of forecast 7

error, 638 MMcf/d34 would have to be made up from other sources in order to balance the 8

system. 9

Balancing the remainder of the core usage against supplies is the responsibility of the 10

System Operator. The System Operator uses load balancing storage resources to balance the 11

deviations between overall customer deliveries and overall customer usage. The core imbalance 12

created by forecast error is part of that system-wide deviation that is addressed by the System 13

Operator. 14

Thus, the Commission should reject TURN’s recommendation that the core not be 15

allocated any load balancing inventory or withdrawal capacity. The core should be required to 16

pay its share of the storage inventory, injection, and withdrawal capacity that is required to 17

provide load balancing services. 18

5 The Commission Should Reject TURN’s Recommendation that Core Injection 19 Capacity Reservation Should Be Based on Ratable Injections over the Summer Season. 20

TURN witness Florio recommends that the core’s summer injection capacity reservation 21

be based on ratable injections over a 214-day summer season, which reduces the core’s 22

31Attachment B: 2018 California Gas Report, SoCalGas Workpapers at 13 footnote 8, average core usage

(excluding CTAs) during December to February. 32 Average retail core usage during December to February of 1,414 MMcf/d x 20% = 283 MMcf/d. 33 Attachment A: 2018 California Gas Report at 92, which includes CTAs in with the core usage. Peak day core

usage (including CTAs) is 3,393 MMcf/d x 94% = 3,189 MMcf/d, which is retail core usage. 34 Peak day retail core usage of 3,189 MMcf/d x 20% = 638 MMcf/d.

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reliability injection reservation from 445 MMcf/d to 386 MMcf/d. The Commission should 1

reject TURN’s recommendation. 2

While it may be reasonable to assume a ratable injection under normal operating 3

conditions, unless the Commission specifically permits Aliso Canyon to operate with a 4

maximum inventory capacity of 68.6 Bcf rather than its current level of 34 Bcf and lifts the Aliso 5

Canyon Withdrawal Protocol, the SoCalGas system will not be operating under normal 6

conditions or even approaching normal conditions. Also, it is unknown if or when the 7

Applicants transmission system will return to “normal” levels of throughput capacity. With 8

reduced capacities of 980 MMcf/d on the SoCalGas Southern System pipelines from 9

Ehrenberg35,36,37 and 60 MMcf/d on Line 85 from California production areas,38 it appears that 10

the SoCalGas backbone transmission system will never return to the full 3875 MMcf/d that is 11

shown as the total backbone capacity in SoCalGas Schedule G-BTS.39 Also, it is unknown what 12

the future capacity of the Northern System pipelines will be after remediation of Lines 4000 and 13

235-2.40 14

Under these suboptimal conditions, circumstances may arise as they did in in early 2017 15

and in early 2018 where the Commission would need to direct accelerated filling of storage 16

fields through a Storage Injection Enhancement Plan in order to ensure that adequate storage 17

inventory levels are maintained during the summer period.41 The Commission explained that 18

because of pipeline outages and other limitations, there might not be sufficient flowing capacity 19

through the summer season to meet both high customer daily demand for flowing supplies, 20

35 There have traditionally been three lines, Line 2000, Line 2001, and Line 5000, that make up the Southern

System pipelines, which interconnect with El Paso Natural Gas Company at Ehrenberg and the combined capacity of these three lines amounted to 1210 MMcf/d.

36 Attachment D: SoCalGas Envoy Notice March 28, 2018, informs shippers that the right-of-way for Line 2000 had lapsed leaving only 980 MMcf/d capacity on the Southern System.

37 Attachment D: SoCalGas Envoy Notice, November 30, 2018. Only two of the three pipeline, Line 5000 and Line 2001, had their right-of-way agreements with the Morongo Band of Mission Indians renewed. The right-of-way agreement for Line 2000 has lapsed. Thus, the capacity of the Southern System has been reduced permanently to 980 MMcf/d.

38 Attachment E: SoCalGas Envoy Maintenance Notice, October 1, 2018 at 2. 39 Attachment F: SoCalGas Schedule G-BTS at Sheet 1. 40 Attachment O: SoCalGas Envoy Maintenance Update, May 3, 2019. 41 Resolution G-3540 at 18-19, Findings 4.

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including high electric generation demand, and to inject gas into storage ratably to meet the 1

winter season storage withdrawal rates.42 2

The Commission should deny TURN’s proposal to reduce the core’s summertime 3

injection capacity allocation so it can only fill its storage inventory capacity on a ratable basis 4

over the entire April through October period. Maintaining the core injection capacity reservation 5

at the higher 455 MMcf/d level gives the core the flexibility to front-load the injections of gas 6

into storage during the moderate shoulder months, April through June, and finish filling storage 7

at a higher rate in October, another shoulder month, when daily demands for flowing supply may 8

be considerably lower. 9

Setting the core injection capacity reservation at the higher 455 MMcf/d level would 10

permit the core to reduce its injection activities on days during the summer months when peak 11

electric usage is likely. This pattern of storage injection would enable the core to save money on 12

gas supplies on days when the demand for gas and the corresponding prices are high. 13

The core would also be in a position to sell gas into the citygate market during high 14

demand periods at a profit, offsetting any added expense of carrying the additional injection 15

capacity. According to SoCalGas Gas Cost Incentive Mechanism (“GCIM”) filings, Gas 16

Acquisition participates regularly in the citygate markets,43 and the core is benefitting from 17

citygate transactions when citygate prices are elevated relative to border and basin prices. 18

6 The Commission Should Reject TURN’s Proposal to Functionalize Capital-Related 19 Revenue Requirement Based on Utility Plant Less Asset Retirement Obligations. 20

TURN’s witness, William Marcus, claims that Asset Retirement Obligations (“AROs”), 21

which are sometimes referred to as the “costs of removal,” are not properly included in the net 22

book value of plant to be used in functionalizing return and taxes.44 Witness Marcus claims that 23

42 Id. at 9. 43 Attachment G: A.18-06-009, SoCalGas GCIM Year 24, Public Advocates Office Monitoring and Evaluation

Report, November 8, 2018, at 13. 44 Marcus Direct at 7.

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“AROs are accounting book entries that have nothing to do with ratemaking”45 Witness Marcus 1

errs in his thinking. 2

Contrary to witness Marcus’s statement, AROs are an appropriate part of the book value 3

of plant. The costs of the AROs are just as much a part of the cost of plant as pipes or valves 4

because once the plant is constructed, the utility is obligated to retire the plant at the end of its 5

useful life, often at significant cost. As described by the Federal Energy Regulatory Commission 6

(“FERC”) in its Order 631: 7

An entity essentially recognizes a liability for the fair value of an 8 asset retirement obligation at the time the asset is constructed, 9 acquired, or when a change in the law creates a legal obligation to 10 perform the retirement activities. Upon initial recognition of that 11 liability, an entity also increases the cost of the related asset that 12 gives rise to the legal obligation by the same amount. The liability 13 is increased over time until the actual retirement activity 14 commences. Additionally, the asset retirement cost capitalized is 15 depreciated over the same life of the related asset giving rise to the 16 obligation.46 17

The FERC in its order made it very clear that the ARO is an “integral part of the costs of the 18

particular asset that gives rise to the asset retirement obligations.”47 19

Consequently, the ARO is an essential part of the plant that is associated with return and 20

taxes, and it is appropriate to use the net book value of plant inclusive of ARO to calculate the 21

transmission share of total net plant as a basis for functionalizing return and taxes. The 22

Commission should reject witness Marcus’s proposal to remove the ARO from net book value in 23

calculating the transmission share of total net plant. 24

Witness Marcus argues that his conclusion is substantiated because the Applicants’ 25

annual reports to the Securities and Exchange Commission acknowledge that there are 26

differences between ratemaking and generally accepted accounting practices.48 It is widely 27

accepted that there are significant differences between ratemaking and generally accepted 28

45 Id. at 6. 46 Attachment H: FERC Docket No. RM02-7-000, Order No. 631 (Issued April 9, 2003) at ¶11 (emphasis

added). 47 Id. at ¶48. 48 Marcus Direct at 9.

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accounting practices, but that does not change the fact that AROs are a very real cost of service. 1

Customers pay for AROs over the entire life of capital assets. The FERC clearly acknowledge 2

this fact in its Order 631. The FERC’s use of ARO in its ratemaking certainly supports my 3

opinion that AROs are a real part of the cost of utility service. Witness Marcus’s proposal 4

inappropriately attempts to diminish this fact. 5

Witness Marcus makes no secret of his motivation for excluding AROs from the 6

functionalization process. His objective is to shift the functionalization of capital related revenue 7

requirement, return, taxes, and depreciation, so that less is associated with distribution and more 8

is associated with transmission and storage, reducing rates for distribution service and increasing 9

rates for transmission service. Witness Marcus claims, for example, that the share of capital-10

related revenue requirement is 8.45 percent for the storage function as proposed by the 11

Applicants, but that the share would increase to 11.13 percent for the storage function if the 12

Commission were to adopt his proposal to exclude AROs from the cost of plant.49 13

The Commission should deny witness Marcus’s proposal as contrary to well-established 14

ratemaking accounting principles. Witness Marcus’s proposal is nothing more than a result-15

oriented attempt to shift costs from the distribution function to the transmission and storage 16

functions. 17

7 The Commission Should Adopt TURN’s Proposal to Assign All Compressor Station 18 O&M to Backbone Transmission. 19

Witness Marcus addresses the Applicants’ proposed subfunctionalization of transmission 20

O&M between the backbone transmission and local transmission subfunctions.50 Witness 21

Marcus correctly observes that the Applicants assign all of the compression station plant to the 22

backbone transmission subfunction.51,52 He also correctly observes that the Applicants split all 23

of transmission O&M between the backbone and local transmission subfunctions on the basis of 24

49 Id. at 8. 50 Id. at 17. 51 Id. at 17. 52 Attachment I: Fung 2020 TCAP Final workpaper at 6.

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the split between backbone mileage and local transmission mileage.53,54 However, since 100 1

percent of the compression station plant is assigned to the backbone subfunction, it is appropriate 2

to assign all of the costs associated with operating that plant (excluding fuel) and maintaining 3

that plant to the backbone subfunction. The Commission should direct the Applicants to make 4

that change to their transmission and storage embedded cost model. 5

8 TURN’s Evaluation of Marginal Customer Cost Methodologies Is Flawed. 6

TURN’s witness Marcus addresses the “theoretical” issues surrounding the choice of 7

marginal customer cost methodologies. Witness Marcus argues that the One Time Hookup Cost 8

(“OTHC”) method, also called the New Customer Only (“NCO”) method, “is vastly superior to 9

the rental method for reflecting cost causation, since the only time when the customer cost is in 10

fact marginal is when the customer is making the decision to connect to the system.”55 This is 11

not true. 12

First, witness Marcus is completely mistaken in assuming that a customer is marginal 13

only when the customer is making a decision about connecting to the utility system. A customer 14

can be marginal regardless of whether that customer is moving into a new location that is not yet 15

connected to the utility or is at an existing location that is already connected. The demand for 16

access is not dependent upon whether the customer is locating at a new site or at an existing site. 17

In each case, the customer is marginal, that is, the customer is deciding whether to access the 18

system. A new customer at a new site will require that new equipment be installed and will 19

begin paying for that equipment through the annualized portion of the customer cost. A new 20

customer at an existing site or an existing customer at an existing site will use the existing hook-21

up equipment and continue to pay the annualized portion of the customer cost. 22

Witness Marcus claims that the opportunity cost of customer access equipment is 23

virtually zero: “But with the exception of salvage value of meters and regulators, the equipment 24

53 Marcus Direct at 17. 54 Attachment I: Fung 2020 TCAP TS Final workpaper at 5. 55 Marcus Direct at 30 (footnote omitted).

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serving a customer facility has no value apart from the location where it exists. It cannot cheaply 1

be moved or installed to serve another customer, and thus its future avoidable costs, or 2

opportunity costs, are negligible.”56 Again, this is not true. 3

Witness Marcus’ fundamental premise that you must be able to relocate the equipment in 4

order to create opportunity cost is flawed. A marginal customer can locate at an existing location 5

or a new location. Thus, the existing equipment could be used at its location to provide service 6

to a different customer if the existing customer chooses to eliminate service and move. This 7

happens all of the time. This is analogous to the rental market for buildings or houses where the 8

opportunity cost to the landlord is represented by the future tenant that would replace the existing 9

tenant, possibly at a higher rent. No one suggests that in order to have an opportunity cost 10

associated with a particular tenant, the landlord would have to somehow move the building to a 11

new location. 12

Witness Marcus is wrong in claiming that the OTHC/NCO method more correctly 13

reflects marginal customer costs. The marginal cost of access is not somehow zero for a 14

customer desiring to access service at an established site but becomes a cost only when there is 15

installation of new service equipment for a customer at a new site. 16

The marginal cost of access is equal to the opportunity cost of service at either a new or 17

existing site. The rental method correctly reflects the associated installation cost annualized 18

through the RECC factor plus the variable costs associated with serving the customer. 19

Witness Marcus also claims that “in a competitive market, the customer would pay the 20

prevailing price of purchasing the customer hookup at the time that it was installed, which would 21

approximate marginal cost. This is the way in which consumers purchase many durable goods 22

that are affixed to their premises and have no other uses apart from the premises (curtains, 23

ceiling insulation, etc.).”57 Witness Marcus then concludes that the OTHC/NCO method best 24

approximates this competitive market situation. Again, witness Marcus errs. 25

56 Id. at 30. 57 Id. at 29.

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While it is true that homeowners would likely purchase durable goods to affix to their 1

premises, renters would only do this if the cost was fairly trivial or the item could be removed for 2

future use at another premise. Otherwise, renters would rent rather than buy durable goods. The 3

level of homeownership only amounts to about 55 percent in California;58 therefore, witness 4

Marcus’ generalization holds only for a little more than half of SoCalGas/SDG&E’s customer 5

base. Again, witness Marcus’ conclusion that the OTHC/NCO method best approximates the 6

competitive market is incorrect. 7

The OTHC/NCO method charges customers different prices for access depending upon 8

whether they are new customers at a new site or new or continuing customers at an existing site. 9

This is improper pricing. Witness Marcus’ arguments attempting to justify this price 10

differentiation are not persuasive. 11

The Commission has not distinguished between new customers at a new site, new 12

customers at an existing site, and continuing customers at an existing site in pricing any other 13

utility services, such as transmission or distribution. The value of customer access and the 14

incremental cost of providing it should be the same for all customers and not a function of the 15

vintage of the equipment used to serve them. The rental method provides the correct cost of 16

providing customer access, that is, both the annualized capital-related cost and variable costs. 17

The Commission should adopt the rental method for establishing marginal customer costs. 18

9 The Commission Should Permanently Approve the Current Language in Rule 30 that 19 Allows for the Trading of Scheduled Quantities on OFO Days. 20

Indicated Shipper’s witness Brubaker discusses how since noncore customers lack access 21

to storage “if they are not able to balance their load on an OFO day, they pay steep penalties.”59 22

I agree with witness Brubaker’s observation. Furthermore, with the limitations on the availability 23

of flowing supplies on the SoCalGas system and the restrictions on storage availability, there 24

58 Attachment J: California’s Low Homeownership Rate to Continue, March 28, 2019,

https://journal.firsttuesday.us/californias-rate-of-homeownership-2/30161/ 59 Brubaker Direct at 21.

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have been a very large number of low and high OFOs declared on the SoCalGas system over the 1

last three and one-half years,60,61,62 which has created extensive burdens on noncore customers. 2

However, witness Brubaker omits any discussion of an existing provision in Rule 30 that 3

helps to offset the burden created by the limited flowing supplies combined with lack of access 4

to storage. SoCalGas Rule 30 currently allows the trading of scheduled quantities for OFO days. 5

The trades take place in the market after the OFO day and the trades must be submitted to the 6

SoCalGas Scheduling Department by 9:00 p.m. on the day following the OFO day. Rule 30 7

currently states: 8

Trading Scheduled Quantities 9

a. Customers may arrange to trade scheduled quantities. The trades 10 are to be arranged outside of the EBB and communicated to the 11 Utility via a trade form. 12

b. Customers may trade scheduled quantities between End Use 13 contracts only by adjusting scheduled quantities after Cycle 6 has 14 been processed. 15

c. Trades will only be available for OFO days. 16

d. Trades must be submitted to the Utility’s scheduling department 17 via email or fax by 9 PM Pacific Clock Time one business day 18 following the Gas Day for which the OFO was declared. 19

e. The Utility may file an expedited Tier 2 Advice Letter to 20 suspend this tariff provision if curtailments are more severe or 21 more frequent due to the offering of this service. Protests and 22 responses to any such Advice Letter would be due within 5 23 business days, and the Utility’s reply would be due within 2 24 business days from the end of the protest period. 63 25

Unfortunately, since the trading of scheduled quantities was originally made available on 26

a temporary basis through a settlement,64 the trading of scheduled quantities will cease to be 27

60 Attachment L: 2017 Customer Forum Presentation, May 8, 2017, at 9, 13. 61 Attachment M: 2018 Customer Forum Presentation, May 9, 2018, at 10, 14. 62 Attachment N: 2019 Customer Forum Presentation, May 7, 2019, at 9, 13. 63 Attachment K: SoCalGas Rule 30, Section N. 64 D.18-11-009, slip op. at 5-7.

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available after the final decision in this proceeding65 unless the Commission acts in this 1

proceeding to make the provision permanent. 2

The trading of scheduled quantities has proven to be enormously valuable to noncore 3

customers during a time of severe constraints and repeated OFOs. The number of trades and the 4

amount of gas traded has grown substantially over the two and one-half years that the trading has 5

been available.66,67,68 As discussed previously, it appears that the SoCalGas backbone 6

transmission system will never return to the full 3875 MMcf/d that is shown as the total 7

backbone capacity in SoCalGas Schedule G-BTS.69 The Commission should act to ensure that 8

trading of scheduled quantities remains permanently available to customers as a tool to manage 9

the burden associated with repeated OFOs. Thus, the Commission should turn this temporary 10

provision into a permanent provision. 11

10 The Commission Should Permanently Approve the Limited Provisions in Rule 30 that 12 Allow SoCalGas to Waive OFO Noncompliance Charges. 13

Indicated Shippers witness Brubaker states that “the significant outages on several of 14

SoCalGas’s major pipelines also results in adverse impacts to noncore customers…[M]ajor 15

pipeline outages are reducing import capability by about 20% below normal.”70 I agree. 16

As I discussed previously, it is unclear when or if the Commission will ever permit Aliso 17

Canyon to operate with a maximum inventory capacity of 68.6 Bcf rather than its current level of 18

34 Bcf or without the Aliso Canyon Withdrawal Protocol. Also, it is unknown if or when the 19

Applicants transmission system will return to “normal” levels of throughput capacity. Capacity 20

on the SoCalGas Southern System pipelines has been reduced to 980 MMcf/d,71,72 capacity on 21

65 Id. at O.P. 3. 66 Attachment L: 2017 Customer Forum Presentation, May 8, 2017, at 21-22. 67 Attachment M: 2018 Customer Forum Presentation, May 9, 2018, at 16-17. 68 Attachment N: 2019 Customer Forum Presentation, May 7, 2019, at 16-17. 69 Attachment F: SoCalGas Schedule G-BTS at Sheet 1. 70 Brubaker Direct at 24-25. 71 Attachment D: SoCalGas Envoy Notice March 28, 2018, informs shippers that the right-of-way for Line 2000

had lapsed leaving only 980 MMcf/d capacity on the Southern System. 72 Attachment D: SoCalGas Envoy Notice, November 30, 2018. Only two of the three pipeline, Line 5000 and

Line 2001, had their right-of-way agreements with the Morongo Band of Mission Indians renewed. The

22

Line 85 from California production areas on has been reduced by 100 MMcf/d73 from 160 1

MMcf/d74 to 60 MMcf/d, and capacity on the SoCalGas Northern System pipelines has been 2

reduced to 870 MMcf/d.75 It is unknown what the future capacity of the Northern System 3

pipelines will be after remediation of Lines 4000 and 235-2.76 4

The capacity limitations on the SoCalGas transmission system can lead to situations 5

where it appropriate to forgive the low OFO noncompliance charges. For example, if there are 6

insufficient supplies to match customer usage, which triggers a low OFO, because there is 7

insufficient capacity on the pipelines to accommodate customer nominations, there is a 8

temporary provision in Rule 30 that the System Operator will waive low OFO noncompliance 9

charges. Section G.1.h of Rule 30 states: “Low OFO noncompliance charges for the gas flow 10

day will be waived when the confirmation process limiting nominations to system capacity cuts 11

previously scheduled BTS nominations during any of the Intraday 1-3 Cycles.” 77 Since there is 12

little or no prospect that the SoCalGas system capacity problems will be solved in the 13

foreseeable future, this provision continues to be very important to customers in managing the 14

difficulties created by the SoCalGas capacity shortage. Commission should approve this 15

provision on a permanent instead of temporary basis. 16

Similarly, under certain circumstances, SoCalGas is allowed to waiver OFO 17

noncompliance charges for electric generators that are dispatched unexpectedly so that these 18

generators have not been able to place adequate nominations for gas supplies during Cycle 1. 19

Given the severe constraints on the SoCalGas system, the Electric Grid operators are dispatching 20

a highly constrained system. However, unexpected events can occur on the electric side forcing 21

right-of-way agreement for Line 2000 has lapsed. Thus, the capacity of the Southern System has been reduced permanently to 980 MMcf/d.

73 Attachment E: SoCalGas Envoy Maintenance Notice, October 1, 2018 at 2. 74 Attachment K: SoCalGas Schedule G-BTS at Sheet 1. 75 Yap Direct, Attachment AD: SoCalGas Envoy Maintenance posting, March 26, 2019. 76 Attachment O: SoCalGas Envoy Maintenance Update, May 3, 2019. 77 Yap Direct, Attachment AH, SoCalGas Rule 30, Section G.1.h.

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late dispatch of generation resources. Rule 30 allow SoCalGas to waive noncompliance charges 1

during these circumstances. Section G.1.i of Rule 30 states: 2

SoCalGas will have the discretion to waive OFO noncompliance 3 charges for an electric generation customer who was dispatched 4 after the Intraday 1 (Cycle 3) nomination deadline in response to 5 (1) a SoCalGas System Operator request to an Electric Grid 6 Operator to reallocate dispatched electric generation load to help 7 maintain gas system reliability and integrity, or (2) an Electric Grid 8 Operator request to the SoCalGas System Operator to help 9 maintain electric system reliability and integrity that can be 10 accommodated by the SoCalGas System Operator at its sole 11 discretion. For electric generators served by a contracted marketer, 12 OFO noncompliance charges can be waived under this section only 13 to the extent the contracted marketer nominates their electric 14 generation customer’s gas to the electric generation customer’s 15 Order Control Code.78 16

Because it is unknown whether the SoCalGas system will have its capacity restored, and 17

if so, how long it will take to accomplish this restoration, SoCalGas needs the ability to adjust 18

OFO charges where circumstances warrant that adjustment. The Commission should approve 19

Section G.1.i on a permanent basis so SoCalGas can continue to waive OFO charges for electric 20

generators that are dispatched unexpectedly to meet electric system reliability issues. 21

78 Yap Direct, Attachment AH, SoCalGas Rule 30, Section G.1.i.