Attachment B: Applicants’ Response to SCGC-01 excerpt€¦ · forecasts relative to estimated actual core usage. Please feel free to contact me if you have any questions regarding

Attachment B: Applicants’ Response to SCGC-01 excerpt

SAN DIEGO GAS & ELECTRIC COMPANY SOUTHERN CALIFORNIA GAS COMPANY

APPLICATION REGARDING FEASIBILITY OF INCORPORATING ADVANCED METER DATA INTO THE CORE BALANCING PROCESS

(A.17-10-002)

(1st DATA REQUEST FROM SOUTHERN CALIFORNIA GENERATION COALITION)

RESPONSE DATE: 01/23/18

__________________________________________________________________________

1

QUESTION 1.1: Please provide a complete set of workpapers to the Direct Testimony of David Mercer, the Direct Testimony of Jerry Stewart, the Direct Testimony of Paul Borkovich, and the Direct Testimony of Sharim Chaudhury. RESPONSE 1.1:

Please see Response 1.2.

Page 1



(A.17-10-002)



__________________________________________________________________________

2

QUESTION 1.2: Please provide a copy of each Excel workbook that was relied upon in preparing the application or the direct testimony in this proceeding. These Excel workbooks should be complete with all data, formulas, and links to other workbooks intact. RESPONSE 1.2:

SCGC-01 Q1.2.zip Please note that, in the Chaudhury workpaper, core forecast percentage errors have been provided in lieu of forecasted and actual core usage numbers.

Page 2



(A.17-10-002)



__________________________________________________________________________

3

QUESTION 1.3: Please provide a copy of each report that SoCalGas has filed with the CPUC Energy Division in compliance with Paragraph 13 of the Second Daily Balancing Settlement approved in D.16-12-015. RESPONSE 1.3:

SCGC-01 Q1.3.zip

Page 3

January 31, 2017

Mr. Franz Cheng Natural Gas Section, Energy Division California Public Utilities Commission 505 Van Ness Avenue San Francisco, CA 94102

RE: SoCalGas and SDG&E Monthly Core Forecasting Report - December 2016

Dear Mr. Cheng:

Enclosed please find the Southern California Gas Company (SoCalGas) and San Diego Gas & Electric Company (SDG&E) Monthly Core Forecasting Report. This monthly report is submitted in compliance with D.16-12-015 for the time period December 1, 2016 – December 31, 2016. The report presents, for each Measurement Day covered by the report, the 7:00 a.m. Demand Forecasting Group core load forecast to estimated actual core usage for the Measurement Day and calculates a percent deviation of each of the demand forecasts relative to estimated actual core usage. Please feel free to contact me if you have any questions regarding this report.

Please note that a portion of the data is being provided as Confidential, and a Confidentiality Declaration pursuant to D.16-08-024 accompanies the Report.

Sincerely,

/s/ Joseph Mock

Joseph Mock Regulatory Case Manager

Attachment

CC: Gurbux Kahlon, CPUC Energy Division Jean Spencer, CPUC Energy Division Gregory Reisinger, CPUC Energy Division Nika Rodgers, CPUC, ORA Pearlie Sabino, CPUC, ORA


Regulatory Affairs 555 West Fifth Street, GT14D6

Los Angeles, CA 90013-1011 Tel: 213.244.3718 Fax: 213.244.4957

[email protected]

Page 4

Confidential and Protected Materials Pursuant to PUC Section 583, GO-66C, and D.16-08-024Mdth Mdth

Date Forecast Estimated Actual % Difference12/1/2016 -2.2%12/2/2016 -7.8%12/3/2016 -3.0%12/4/2016 -6.5%12/5/2016 4.1%12/6/2016 6.7%12/7/2016 1.2%12/8/2016 3.2%12/9/2016 0.5%

12/10/2016 8.5%12/11/2016 13.4%12/12/2016 16.7%12/13/2016 8.1%12/14/2016 6.2%12/15/2016 2.4%12/16/2016 16.9%12/17/2016 7.7%12/18/2016 -4.4%12/19/2016 -1.2%12/20/2016 -15.0%12/21/2016 -14.9%12/22/2016 -2.4%12/23/2016 -8.2%12/24/2016 3.6%12/25/2016 11.2%12/26/2016 -5.1%12/27/2016 -10.6%12/28/2016 -14.6%12/29/2016 -7.5%12/30/2016 -0.9%12/31/2016 1.3%

Total -0.2%

Note:1.2. Both the forecast and estimatd actual data represent midnight to midnight gas consumption. 3.

4.

5.

6. The prior day 7:00am forecasts were used for 12/4 and 12/17 because both Envoy and Gas Acqusition did not receive either the 5 am or the 7 am forecast on those 2 days.

The Retail Core estimated actual demand for SDG&E is the daily AMI core data (including company use), to which an estimated LUAF has been added.

Daily Core Demand Forecast Performance Report for December 2016Combined SoCalGas and SDG&E

% Difference = (Forecast - Estimated Recorded) / (Estimated Recorded)

Forecast and Estimated Actual data are for retail core (core sales) only and include company use and loss & unaccounted for gas.The retail core estimated actual demand for SoCalGas is the physical residual after subtracting noncore and core transport agents (CAT) physical gas demand from the measured daily total system gas sendout, which has been converted to Dth using a 1.0273 MDth/MMcf heat rate (core average monthly heat rates have ranged from 1.02 to 1.04 MDth/MMcf). The CAT demand is estimated based on the historical CAT usage per meter with its meter growth assumption.

Page 5

February 28, 2017

Mr. Franz Cheng Natural Gas Section, Energy Division California Public Utilities Commission 505 Van Ness Avenue San Francisco, CA 94102

RE: SoCalGas and SDG&E Monthly Core Forecasting Report - January 2017

Dear Mr. Cheng:

Enclosed please find the Southern California Gas Company (SoCalGas) and San Diego Gas & Electric Company (SDG&E) Monthly Core Forecasting Report. This monthly report is submitted in compliance with D.16-12-015 for the time period January 1, 2017 – January 31, 2017. The report presents, for each Measurement Day covered by the report, the 7:00 a.m. Demand Forecasting Group core load forecast to estimated actual core usage for the Measurement Day and calculates a percent deviation of each of the demand forecasts relative to estimated actual core usage. Please feel free to contact me if you have any questions regarding this report.

Please note that a portion of the data is being provided as Confidential, and a Confidentiality Declaration pursuant to D.16-08-024 accompanies the Report.

Sincerely,

/s/ Joseph Mock


Attachment

CC: Gurbux Kahlon, CPUC Energy Division Jean Spencer, CPUC Energy Division Gregory Reisinger, CPUC Energy Division Nika Rodgers, CPUC, ORA Pearlie Sabino, CPUC, ORA


Regulatory Affairs 555 West Fifth Street, GT14D6

Los Angeles, CA 90013-1011 Tel: 213.244.3718 Fax: 213.244.4957

[email protected]

Page 6

Mdth Mdth degrees F degrees F degrees F

Date Forecast Estimated Actual % Difference Temp Forecast Temp Actual Forecast Error

1/1/2017 11.2% 51.4 50.2 1.2

1/2/2017 -1.8% 53.6 52.9 0.7

1/3/2017 -7.0% 54.2 52.3 1.9

1/4/2017 4.8% 53.9 53.6 0.3

1/5/2017 -2.0% 57.6 57.4 0.1

1/6/2017 3.4% 56.1 56.5 -0.4

1/7/2017 -6.7% 57.4 58.5 -1.1

1/8/2017 1.7% 62.0 63.7 -1.8

1/9/2017 3.4% 58.5 58.6 0.0

1/10/2017 -2.9% 56.8 54.8 2.0

1/11/2017 -0.5% 58.3 58.9 -0.6

1/12/2017 0.3% 54.4 54.1 0.3

1/13/2017 -1.0% 54.4 54.0 0.4

1/14/2017 -7.3% 57.4 57.0 0.4

1/15/2017 -1.7% 56.4 55.2 1.2

1/16/2017 -8.4% 57.3 56.8 0.5

1/17/2017 -2.8% 54.9 54.8 0.1

1/18/2017 -1.6% 53.5 52.2 1.3

1/19/2017 1.3% 56.0 56.4 -0.3

1/20/2017 -16.1% 55.4 53.8 1.5

1/21/2017 -1.8% 53.5 52.8 0.8

1/22/2017 -17.6% 54.6 51.9 2.7

1/23/2017 -6.5% 51.6 51.6 0.0

1/24/2017 -4.5% 49.3 48.1 1.2

1/25/2017 -4.1% 50.0 48.5 1.5

1/26/2017 -5.9% 50.9 50.0 0.9

1/27/2017 -13.0% 53.9 53.8 0.1

1/28/2017 -8.6% 55.6 57.9 -2.3

1/29/2017 3.5% 58.7 60.3 -1.6

1/30/2017 9.9% 61.5 61.9 -0.4

1/31/2017 12.9% 60.1 60.9 -0.7

Total -2.9% Average 55.5 55.1

Note:

1.

2. Both the forecast and estimatd actual data represent midnight to midnight gas consumption.

3.

4.

5.

6.

7.Part of the load forecast error can be explained by the forecast error in temperature

provided by the third party vendor.

The Retail Core estimated actual demand for SDG&E is the daily AMI core data (including

company use), to which an estimated LUAF has been added.


Forecast and Estimated Actual data are for retail core (core sales) only and include

company use and loss & unaccounted for gas.

The retail core estimated actual demand for SoCalGas is the physical residual after

subtracting noncore and core transport agents (CAT) physical gas demand from the

measured daily total system gas sendout, which has been converted to Dth using a 1.0273

MDth/MMcf heat rate (core average monthly heat rates have ranged from 1.02 to 1.04

MDth/MMcf). The CAT demand is estimated based on the historical CAT usage per meter

with its meter growth assumption.

The prior day 7:00am forecasts were used for 1/9 and 1/28 because both Envoy and Gas

Acquisition did not receive either the 5 am or the 7 am forecast on those 2 days.

Daily Core Demand Forecast Performance Report for January 2017Combined SoCalGas and SDG&E

Confidential and Protected Materials Pursuant to PUC Section 583, GO-66C, and D.16-08-024

Page 7

March 31, 2017 Mr. Franz Cheng Natural Gas Section, Energy Division California Public Utilities Commission 505 Van Ness Avenue San Francisco, CA 94102 RE: SoCalGas and SDG&E Monthly Core Forecasting Report - February 2017 Dear Mr. Cheng: Enclosed please find the Southern California Gas Company (SoCalGas) and San Diego Gas & Electric Company (SDG&E) Monthly Core Forecasting Report. This monthly report is submitted in compliance with D.16-12-015 for the time period February 1, 2017 – February 28, 2017. The report presents, for each Measurement Day covered by the report, the 7:00 a.m. Demand Forecasting Group core load forecast to estimated actual core usage for the Measurement Day and calculates a percent deviation of each of the demand forecasts relative to estimated actual core usage. Please feel free to contact me if you have any questions regarding this report. Please note that a portion of the data is being provided as Confidential, and a Confidentiality Declaration pursuant to D.16-08-024 accompanies the Report. Sincerely,

/s/ Joseph Mock Joseph Mock Regulatory Case Manager Attachment CC: Gurbux Kahlon, CPUC Energy Division

Jean Spencer, CPUC Energy Division Gregory Reisinger, CPUC Energy Division Nika Rodgers, CPUC, ORA Pearlie Sabino, CPUC, ORA

Joseph Mock

Regulatory Case Manager Regulatory Affairs

555 West Fifth Street, GT14D6 Los Angeles, CA 90013-1011

Tel: 213.244.3718 Fax: 213.244.4957

[email protected]

Page 8


Date Forecast Estimated Actual % Difference Temp Forecast Temp Actual Forecast Error

2/1/2017 -4.0% 58.0 57.3 0.7

2/2/2017 2.6% 57.0 57.2 -0.2

2/3/2017 -1.4% 58.9 57.5 1.3

2/4/2017 2.9% 59.1 59.3 -0.1

2/5/2017 -3.5% 56.7 54.4 2.3

2/6/2017 -8.4% 57.3 55.8 1.5

2/7/2017 1.6% 60.4 60.7 -0.2

2/8/2017 0.4% 64.5 64.3 0.2

2/9/2017 5.9% 64.8 65.0 -0.2

2/10/2017 9.3% 61.3 60.5 0.8

2/11/2017 3.3% 59.5 59.6 -0.1

2/12/2017 -1.0% 60.4 60.4 0.0

2/13/2017 0.7% 62.2 61.6 0.6

2/14/2017 2.9% 62.7 62.3 0.4

2/15/2017 3.2% 62.5 63.0 -0.4

2/16/2017 12.2% 59.8 59.9 0.0

2/17/2017 -10.8% 58.4 57.5 0.9

2/18/2017 -5.1% 57.2 55.7 1.5

2/19/2017 -0.6% 56.9 55.7 1.1

2/20/2017 1.5% 57.2 58.0 -0.8

2/21/2017 7.1% 60.4 62.4 -1.9

2/22/2017 10.5% 57.0 57.2 -0.3

2/23/2017 2.0% 52.9 52.7 0.2

2/24/2017 4.8% 51.9 51.6 0.3

2/25/2017 5.1% 52.0 51.3 0.7

2/26/2017 1.0% 53.8 52.5 1.3

2/27/2017 -7.2% 54.6 53.5 1.1

2/28/2017 5.4% 54.1 54.3 -0.2

Total 1.1% Average 58.3 57.9

Note:

1.


3.

4.

5.

6.

Daily Core Demand Forecast Performance Report for February 2017Combined SoCalGas and SDG&E

Confidential and Protected Materials Pursuant to PUC Section 583, GO-66C, and D.16-08-024 (Grey Highlighted Cells)

Part of the load forecast error can be explained by the forecast error in temperature









measured daily total system gas sendout, which has been converted to Dth using a

1.0273 MDth/MMcf heat rate (core average monthly heat rates have ranged from 1.02

to 1.04 MDth/MMcf). The CAT demand is estimated based on the historical CAT usage

per meter with its meter growth assumption.

Page 9

April 28, 2017 Mr. Franz Cheng Natural Gas Section, Energy Division California Public Utilities Commission 505 Van Ness Avenue San Francisco, CA 94102 RE: SoCalGas and SDG&E Monthly Core Forecasting Report - March 2017 Dear Mr. Cheng: Enclosed please find the Southern California Gas Company (SoCalGas) and San Diego Gas & Electric Company (SDG&E) Monthly Core Forecasting Report. This monthly report is submitted in compliance with D.16-12-015 for the time period March 1, 2017 – March 31, 2017. The report presents, for each Measurement Day covered by the report, the 7:00 a.m. Demand Forecasting Group core load forecast to estimated actual core usage for the Measurement Day and calculates a percent deviation of each of the demand forecasts relative to estimated actual core usage. Please feel free to contact me if you have any questions regarding this report. Please note that a portion of the data is being provided as Confidential, and a Confidentiality Declaration pursuant to D.16-08-024 accompanies the Report. Sincerely,



Joseph Mock



Tel: 213.244.3718 Fax: 213.244.4957

[email protected]

Page 10


Date Forecast Estimated Actual % Difference Temp Forecast Temp Actual Forecast Error OFO Status

3/1/2017 -13.8% 57.6 57.7 -0.2 Both

3/2/2017 -14.5% 60.7 61.6 -0.8 Low

3/3/2017 -7.9% 62.0 62.8 -0.7 Low

3/4/2017 -4.6% 59.4 59.0 0.4 Low

3/5/2017 3.2% 55.2 57.0 -1.8 Low

3/6/2017 -6.7% 54.0 53.0 1.0 No

3/7/2017 -14.4% 59.1 58.9 0.2 Low

3/8/2017 -13.4% 65.4 65.4 0.0 Both

3/9/2017 4.7% 67.6 68.1 -0.5 Low

3/10/2017 8.7% 67.5 67.1 0.4 High

3/11/2017 4.9% 67.5 67.0 0.5 High

3/12/2017 9.9% 68.4 67.5 0.9 High

3/13/2017 17.4% 69.4 69.2 0.3 Low

3/14/2017 17.1% 68.7 69.1 -0.4 High

3/15/2017 19.8% 69.8 70.4 -0.7 High

3/16/2017 16.3% 67.5 66.7 0.9 High

3/17/2017 10.1% 67.1 66.4 0.6 High

3/18/2017 12.4% 65.3 65.7 -0.4 High

3/19/2017 8.6% 65.1 65.1 0.0 High

3/20/2017 24.2% 62.8 63.7 -0.9 Low

3/21/2017 16.3% 60.8 61.2 -0.4 High

3/22/2017 20.2% 60.3 62.5 -2.2 High

3/23/2017 9.2% 60.0 60.0 0.0 High

3/24/2017 12.6% 59.5 59.7 -0.2 High

3/25/2017 11.9% 60.5 60.9 -0.4 High

3/26/2017 6.6% 61.7 61.4 0.3 High

3/27/2017 4.2% 62.9 62.4 0.4 Low

3/28/2017 -5.0% 64.5 64.5 0.0 High

3/29/2017 -0.9% 67.3 67.2 0.0 Both

3/30/2017 6.0% 64.5 63.6 0.9 Both

3/31/2017 5.4% 61.4 62.7 -1.3 High

Total 3.8% Average 63.3 63.5 High OFOs 17

Low OFOs 9

Note: High and Low OFOs 4

1. No OFOs 1


3.

4.

5.

6.

Daily Core Demand Forecast Performance Report for March 2017Combined SoCalGas and SDG&E















Page 11

May 31, 2017 Mr. Franz Cheng Natural Gas Section, Energy Division California Public Utilities Commission 505 Van Ness Avenue San Francisco, CA 94102 RE: SoCalGas and SDG&E Monthly Core Forecasting Report - April 2017 Dear Mr. Cheng: Enclosed please find the Southern California Gas Company (SoCalGas) and San Diego Gas & Electric Company (SDG&E) Monthly Core Forecasting Report. This monthly report is submitted in compliance with D.16-12-015 and D.17-03-020 for the time period April 1, 2017 – April 30, 2017. The report presents, for each Measurement Day covered by the report, the 7:00 a.m. Demand Forecasting Group core load forecast to estimated actual core usage for the Measurement Day and calculates a percent deviation of each of the demand forecasts relative to estimated actual core usage. Please feel free to contact me if you have any questions regarding this report. Please note that a portion of the data is being provided as Confidential, and a Confidentiality Declaration pursuant to D.16-08-024 accompanies the Report. Sincerely,



Joseph Mock



Tel: 213.244.3718 Fax: 213.244.4957

[email protected]

Page 12



4/1/2017 -10.9% 63.7 62.2 1.6 High

4/2/2017 -1.3% 64.8 65.0 -0.2 Low

4/3/2017 12.3% 61.7 61.0 0.7 Low

4/4/2017 -5.1% 65.4 65.5 0.0 High

4/5/2017 0.9% 68.3 68.7 -0.4 Low

4/6/2017 -0.1% 67.1 66.9 0.3 None

4/7/2017 3.1% 64.1 64.0 0.0 High

4/8/2017 10.1% 61.7 61.4 0.3 High

4/9/2017 -0.1% 61.1 60.1 1.0 None

4/10/2017 -3.3% 63.1 62.9 0.3 Low

4/11/2017 -0.4% 63.5 64.3 -0.8 None

4/12/2017 2.3% 63.4 63.4 0.0 None

4/13/2017 12.4% 61.8 64.0 -2.2 None

4/14/2017 5.2% 61.0 60.6 0.4 None

4/15/2017 -6.8% 63.8 62.8 1.0 None

4/16/2017 -1.7% 65.2 65.6 -0.3 None

4/17/2017 1.2% 64.8 65.9 -1.1 Both

4/18/2017 4.4% 65.9 67.4 -1.5 High

4/19/2017 2.9% 66.6 66.7 -0.2 Low

4/20/2017 5.2% 67.4 66.8 0.6 Both

4/21/2017 6.4% 71.6 72.0 -0.4 High

4/22/2017 12.2% 73.1 74.0 -0.9 High

4/23/2017 11.8% 69.3 69.5 -0.2 High

4/24/2017 7.6% 66.2 65.0 1.2 High

4/25/2017 2.3% 66.6 65.6 0.9 None

4/26/2017 5.2% 69.0 67.6 1.3 High

4/27/2017 7.1% 68.7 68.1 0.6 High

4/28/2017 5.2% 70.5 70.7 -0.2 None

4/29/2017 5.4% 71.1 72.1 -1.0 None

4/30/2017 10.0% 69.3 70.6 -1.3 None

Total 3.2% Average 66.0 66.0 High OFOs 11

Low OFOs 5

Note: High and Low OFOs 2

1. No OFOs 12


3.

4.

5.

6.

7. Due to data system error, the 7:00 am forecast from 1 day prior was used for 4/12 and

4/30, the 7:00 am forecast from 2 days prior was used for 4/13, and the 7:00 am forecast

from 3 days prior was used for 4/14. In addition, the 5:00 am forecast was used for 4/15

instead of the 7:00 am forecast. Moreover, due to the SDG&E estimated actual AMI data

missing from 4/11 to 4/14, the recorded MCS data were used in place of the AMI data for

those days.

Daily Core Demand Forecast Performance Report for April 2017Combined SoCalGas and SDG&E















Page 13

June 30, 2017 Mr. Franz Cheng Natural Gas Section, Energy Division California Public Utilities Commission 505 Van Ness Avenue San Francisco, CA 94102 RE: SoCalGas and SDG&E Monthly Core Forecasting Report - May 2017 Dear Mr. Cheng: Enclosed please find the Southern California Gas Company (SoCalGas) and San Diego Gas & Electric Company (SDG&E) Monthly Core Forecasting Report. This monthly report is submitted in compliance with D.16-12-015 and D.17-03-020 for the time period May 1, 2017 – May 31, 2017. The report presents, for each Measurement Day covered by the report, the 7:00 a.m. Demand Forecasting Group core load forecast to estimated actual core usage for the Measurement Day and calculates a percent deviation of each of the demand forecasts relative to estimated actual core usage. Please feel free to contact me if you have any questions regarding this report. Please note that a portion of the data is being provided as Confidential, and a Confidentiality Declaration pursuant to D.16-08-024 accompanies the Report. Sincerely,



Joseph Mock



Tel: 213.244.3718 Fax: 213.244.4957

[email protected]

Page 14



5/1/2017 6.5% 70.4 70.5 0.0 Low

5/2/2017 1.5% 71.7 71.8 -0.2 High

5/3/2017 12.4% 72.6 72.2 0.4 None

5/4/2017 6.6% 71.9 72.3 -0.3 None

5/5/2017 -0.1% 67.1 66.3 0.7 High

5/6/2017 12.7% 60.1 61.9 -1.8 High

5/7/2017 9.1% 56.8 55.9 0.9 None

5/8/2017 -8.4% 61.2 60.4 0.8 None

5/9/2017 0.9% 62.6 62.9 -0.3 None

5/10/2017 -6.8% 63.7 63.7 0.0 None

5/11/2017 -9.4% 65.6 65.4 0.2 None

5/12/2017 -6.9% 65.6 65.9 -0.3 None

5/13/2017 -8.2% 65.7 65.3 0.4 None

5/14/2017 -0.9% 63.1 62.7 0.4 None

5/15/2017 4.4% 60.3 60.0 0.3 High

5/16/2017 -5.7% 61.8 60.6 1.2 High

5/17/2017 -7.9% 63.0 61.9 1.1 None

5/18/2017 -13.1% 65.8 65.0 0.9 None

5/19/2017 2.3% 70.5 71.3 -0.8 None

5/20/2017 4.7% 74.5 75.3 -0.9 High

5/21/2017 13.0% 74.8 74.6 0.2 High

5/22/2017 8.5% 73.1 72.2 0.9 Both

5/23/2017 7.6% 72.5 73.1 -0.6 None

5/24/2017 0.4% 68.3 69.2 -0.8 None

5/25/2017 -3.6% 64.6 64.0 0.6 High

5/26/2017 0.1% 64.4 65.8 -1.4 High

5/27/2017 -5.4% 66.2 65.7 0.4 High

5/28/2017 2.7% 68.1 67.6 0.5 High

5/29/2017 -1.6% 68.9 67.8 1.1 None

5/30/2017 -1.4% 68.5 67.4 1.1 None

5/31/2017 -3.3% 67.4 65.7 1.8 High


High OFOs 12

Note: Low OFOs 1

1. High and Low OFOs 1

2. Both the forecast and estimatd actual data represent midnight to midnight gas consumption. No OFOs 17

3.

4.

5.

6.

Daily Core Demand Forecast Performance Report for May 2017Combined SoCalGas and SDG&E















Page 15

July 31, 2017 Mr. Franz Cheng Natural Gas Section, Energy Division California Public Utilities Commission 505 Van Ness Avenue San Francisco, CA 94102 RE: SoCalGas and SDG&E Monthly Core Forecasting Report - June 2017 Dear Mr. Cheng: Enclosed please find the Southern California Gas Company (SoCalGas) and San Diego Gas & Electric Company (SDG&E) Monthly Core Forecasting Report. This monthly report is submitted in compliance with D.16-12-015 and D.17-03-020 for the time period June 1, 2017 – June 30, 2017. The report presents, for each Measurement Day covered by the report, the 7:00 a.m. Demand Forecasting Group core load forecast to estimated actual core usage for the Measurement Day and calculates a percent deviation of each of the demand forecasts relative to estimated actual core usage. Please feel free to contact me if you have any questions regarding this report. Please note that a portion of the data is being provided as Confidential, and a Confidentiality Declaration pursuant to D.16-08-024 accompanies the Report. Sincerely,

/s/ Joseph Mock Joseph Mock Regulatory Case Manager Attachment CC: Dorothy Duda, CPUC Energy Division


Joseph Mock



Tel: 213.244.3718 Fax: 213.244.4957

[email protected]

Page 16



6/1/2017 -11.7% 69.0 67.9 1.1 High OFO

6/2/2017 -3.4% 71.2 71.1 0.1 No OFO

6/3/2017 -5.8% 71.7 71.9 -0.2 No OFO

6/4/2017 -1.3% 71.0 70.6 0.5 No OFO

6/5/2017 -4.3% 70.1 69.7 0.4 Low OFO

6/6/2017 -9.1% 69.1 68.6 0.5 High OFO

6/7/2017 -11.8% 67.8 68.3 -0.4 High OFO

6/8/2017 -10.7% 68.3 68.4 -0.1 No OFO

6/9/2017 -6.5% 68.4 68.8 -0.4 High OFO

6/10/2017 -5.9% 66.4 67.6 -1.2 No OFO

6/11/2017 -6.6% 64.5 65.3 -0.7 High OFO

6/12/2017 -9.7% 65.5 65.3 0.2 No OFO

6/13/2017 -4.5% 68.7 68.5 0.2 High OFO

6/14/2017 -5.8% 72.7 72.6 0.1 High OFO

6/15/2017 4.4% 74.3 74.4 -0.1 No OFO

6/16/2017 4.7% 76.6 76.7 -0.1 High OFO

6/17/2017 1.3% 75.7 76.3 -0.5 High OFO

6/18/2017 7.1% 75.7 75.8 -0.1 High OFO

6/19/2017 19.7% 77.2 76.8 0.4 Low OFO

6/20/2017 11.9% 78.2 78.0 0.2 Low OFO

6/21/2017 18.1% 78.5 77.0 1.5 Low OFO

6/22/2017 3.7% 74.6 73.7 0.8 No OFO

6/23/2017 9.3% 73.2 73.4 -0.1 High OFO

6/24/2017 3.4% 74.6 73.7 0.9 High OFO

6/25/2017 15.5% 78.0 79.4 -1.4 No OFO

6/26/2017 19.7% 80.8 80.6 0.2 Low OFO

6/27/2017 5.4% 76.1 77.5 -1.4 Both OFO

6/28/2017 6.2% 72.5 72.5 0.0 High OFO

6/29/2017 6.6% 70.8 72.5 -1.6 High OFO

6/30/2017 5.1% 71.6 72.1 -0.4 High OFO


High OFOs 15

Note: Low OFOs 5



3.

4.

5.

6.

Daily Core Demand Forecast Performance Report for June 2017Combined SoCalGas and SDG&E















Page 17

August 31, 2017 Mr. Franz Cheng Natural Gas Section, Energy Division California Public Utilities Commission 505 Van Ness Avenue San Francisco, CA 94102

RE: SoCalGas and SDG&E Monthly Core Forecasting Report - July 2017 Dear Mr. Cheng: Enclosed please find the Southern California Gas Company (SoCalGas) and San Diego Gas & Electric Company (SDG&E) Monthly Core Forecasting Report. This monthly report is submitted in compliance with D.16-12-015 and D.17-03-020 for the time period July 1, 2017 – July 31, 2017. The report presents, for each Measurement Day covered by the report, the 7:00 a.m. Demand Forecasting Group core load forecast to estimated actual core usage for the Measurement Day and calculates a percent deviation of each of the demand forecasts relative to estimated actual core usage. Please feel free to contact me if you have any questions regarding this report. Please note that a portion of the data is being provided as Confidential, and a Confidentiality Declaration pursuant to D.16-08-024 accompanies the Report. Sincerely,



Joseph Mock



Tel: 213.244.3718 Fax: 213.244.4957

[email protected]

Page 18

Mdth Mdth degrees F degrees F degrees FDate Forecast Estimated Actual % Difference Temp Forecast Temp Actual Forecast Error OFO Status

7/1/2017 -9.9% 71.0 71.2 -0.2 No OFO7/2/2017 -1.9% 71.2 73.6 -2.4 No OFO7/3/2017 -0.3% 72.6 74.5 -1.9 No OFO7/4/2017 0.2% 75.5 76.1 -0.6 No OFO7/5/2017 7.0% 77.4 77.1 0.3 No OFO7/6/2017 3.3% 79.2 78.6 0.6 No OFO7/7/2017 0.9% 82.6 82.6 -0.1 Low OFO7/8/2017 8.1% 83.8 83.9 -0.1 No OFO7/9/2017 14.1% 81.1 82.8 -1.7 High OFO

7/10/2017 10.9% 81.6 81.6 0.0 No OFO7/11/2017 0.6% 78.5 78.7 -0.1 High OFO7/12/2017 1.1% 76.7 76.8 -0.1 High OFO7/13/2017 3.1% 76.7 77.0 -0.3 No OFO7/14/2017 0.4% 76.8 76.6 0.2 High OFO7/15/2017 5.4% 79.4 78.8 0.6 High OFO7/16/2017 6.4% 78.4 78.2 0.2 High OFO7/17/2017 -0.3% 77.9 77.9 -0.1 No OFO7/18/2017 1.5% 77.1 77.5 -0.4 High OFO7/19/2017 -1.8% 77.3 78.5 -1.2 No OFO7/20/2017 6.0% 77.5 78.3 -0.9 No OFO7/21/2017 -2.0% 76.5 76.4 0.1 High OFO7/22/2017 2.0% 77.3 77.0 0.3 High OFO7/23/2017 7.2% 77.5 77.9 -0.5 High OFO7/24/2017 0.1% 75.5 75.4 0.1 No OFO7/25/2017 1.1% 75.7 76.3 -0.5 High OFO7/26/2017 1.2% 76.5 76.6 -0.1 No OFO7/27/2017 -1.7% 77.7 77.9 -0.2 No OFO7/28/2017 -2.7% 76.8 76.3 0.4 High OFO7/29/2017 -0.5% 75.4 76.5 -1.1 High OFO7/30/2017 2.0% 75.5 76.7 -1.2 High OFO7/31/2017 77.8 76.7 No OFO

Total 1.8% Average 77.2 77.6High OFOs 14

Note: Low OFOs 11. High and Low OFOs 02. Both the forecast and estimatd actual data represent midnight to midnight gas consumption. No OFOs 163.

4.

5.

6.

Daily Core Demand Forecast Performance Report for July 2017Combined SoCalGas and SDG&E


Part of the load forecast error can be explained by the forecast error in temperature provided by the third party vendor.

The Retail Core estimated actual demand for SDG&E is the daily AMI core data (including company use), to which an estimated LUAF has been added.


Forecast and Estimated Actual data are for retail core (core sales) only and include company use and loss & unaccounted for gas.

The retail core estimated actual demand for SoCalGas is the physical residual after subtracting noncore and core transport agents (CAT) physical gas demand from the measured daily total system gas sendout, which has been converted to Dth using a 1.0273 MDth/MMcf heat rate (core average monthly heat rates have ranged from 1.02 to 1.04 MDth/MMcf). The CAT demand is estimated based on the historical CAT usage per meter with its meter growth assumption.

Page 19

September 29, 2017 Mr. Franz Cheng Natural Gas Section, Energy Division California Public Utilities Commission 505 Van Ness Avenue San Francisco, CA 94102 RE: SoCalGas and SDG&E Monthly Core Forecasting Report - August 2017 Dear Mr. Cheng: Enclosed please find the Southern California Gas Company (SoCalGas) and San Diego Gas & Electric Company (SDG&E) Monthly Core Forecasting Report. This monthly report is submitted in compliance with D.16-12-015 and D.17-03-020 for the time period August 1, 2017 – August 31, 2017. The report presents, for each Measurement Day covered by the report, the 7:00 a.m. Demand Forecasting Group core load forecast to estimated actual core usage for the Measurement Day and calculates a percent deviation of each of the demand forecasts relative to estimated actual core usage. Please feel free to contact me if you have any questions regarding this report. Please note that a portion of the data is being provided as Confidential, and a Confidentiality Declaration pursuant to D.16-08-024 accompanies the Report. Sincerely,



Joseph Mock



Tel: 213.244.3718 Fax: 213.244.4957

[email protected]

Page 20



8/1/2017 1.5% 81.2 81.9 -0.7 No OFO

8/2/2017 7.4% 83.4 83.8 -0.3 No OFO

8/3/2017 7.3% 83.1 83.6 -0.5 No OFO

8/4/2017 0.6% 79.6 80.9 -1.3 No OFO

8/5/2017 4.3% 77.3 77.8 -0.5 High OFO

8/6/2017 6.4% 76.5 76.6 -0.1 High OFO

8/7/2017 2.6% 76.6 76.8 -0.2 High OFO

8/8/2017 4.1% 78.2 78.3 -0.1 High OFO

8/9/2017 6.2% 77.4 76.7 0.7 No OFO

8/10/2017 0.8% 77.8 77.6 0.2 No OFO

8/11/2017 3.0% 78.0 77.4 0.5 No OFO

8/12/2017 -0.6% 77.0 76.9 0.1 No OFO

8/13/2017 4.8% 74.8 76.6 -1.8 High OFO

8/14/2017 -3.6% 72.7 73.9 -1.2 No OFO

8/15/2017 -2.3% 69.9 71.0 -1.1 High OFO

8/16/2017 -5.9% 71.4 72.8 -1.4 High OFO

8/17/2017 -2.4% 73.1 73.6 -0.5 No OFO

8/18/2017 -1.1% 73.9 74.1 -0.1 No OFO

8/19/2017 -5.1% 74.1 74.7 -0.6 No OFO

8/20/2017 -0.6% 73.5 74.5 -1.0 High OFO

8/21/2017 0.1% 74.4 75.1 -0.7 Low OFO

8/22/2017 -7.9% 74.9 74.2 0.7 No OFO

8/23/2017 -0.9% 73.7 74.2 -0.5 Low OFO

8/24/2017 -2.7% 74.0 73.5 0.5 High OFO

8/25/2017 -2.6% 75.3 74.6 0.7 High OFO

8/26/2017 -1.5% 77.2 78.3 -1.1 No OFO

8/27/2017 5.4% 79.2 77.7 1.5 Low OFO

8/28/2017 7.8% 82.0 81.4 0.6 Low OFO

8/29/2017 4.9% 84.7 84.5 0.2 Low OFO

8/30/2017 10.5% 84.3 84.3 0.0 No OFO

8/31/2017 12.5% 86.1 86.7 -0.6 No OFO


High OFOs 10

Note: Low OFOs 5



3.

4.

5.

6.

Daily Core Demand Forecast Performance Report for August 2017Combined SoCalGas and SDG&E















Page 21

October 31, 2017 Mr. Franz Cheng Natural Gas Section, Energy Division California Public Utilities Commission 505 Van Ness Avenue San Francisco, CA 94102 RE: SoCalGas and SDG&E Monthly Core Forecasting Report - September 2017 Dear Mr. Cheng: Enclosed please find the Southern California Gas Company (SoCalGas) and San Diego Gas & Electric Company (SDG&E) Monthly Core Forecasting Report. This monthly report is submitted in compliance with D.16-12-015 and D.17-03-020 for the time period September 1, 2017 – September 30, 2017. The report presents, for each Measurement Day covered by the report, the 7:00 a.m. Demand Forecasting Group core load forecast to estimated actual core usage for the Measurement Day and calculates a percent deviation of each of the demand forecasts relative to estimated actual core usage. Please feel free to contact me if you have any questions regarding this report. Please note that a portion of the data is being provided as Confidential, and a Confidentiality Declaration pursuant to D.16-08-024 accompanies the Report. Sincerely,



Joseph Mock



Tel: 213.244.3718 Fax: 213.244.4957

[email protected]

Page 22



9/1/2017 19.6% 86.7 87.8 -1.1 Low OFO

9/2/2017 17.6% 86.1 87.8 -1.7 No OFO

9/3/2017 25.7% 84.4 88.6 -4.1 No OFO

9/4/2017 9.7% 79.1 78.6 0.5 High OFO

9/5/2017 9.0% 77.6 78.2 -0.5 No OFO

9/6/2017 3.2% 79.0 78.3 0.7 No OFO

9/7/2017 3.2% 77.0 77.0 -0.1 No OFO

9/8/2017 1.1% 75.5 75.7 -0.2 No OFO

9/9/2017 -1.8% 75.1 75.4 -0.3 High OFO

9/10/2017 -1.4% 78.1 79.0 -0.9 High OFO

9/11/2017 9.8% 80.5 82.3 -1.8 Low OFO

9/12/2017 0.9% 77.6 77.0 0.6 No OFO

9/13/2017 -2.5% 73.0 73.4 -0.4 No OFO

9/14/2017 -8.8% 70.4 70.1 0.3 No OFO

9/15/2017 -7.3% 70.9 70.9 0.0 High OFO

9/16/2017 -10.1% 71.3 70.9 0.4 No OFO

9/17/2017 -6.4% 71.1 71.4 -0.3 No OFO

9/18/2017 -13.8% 70.7 70.4 0.3 Low OFO

9/19/2017 -8.2% 70.3 71.3 -1.0 No OFO

9/20/2017 -11.2% 70.0 71.2 -1.2 No OFO

9/21/2017 -12.9% 66.9 68.7 -1.7 No OFO

9/22/2017 -17.2% 66.2 65.8 0.4 No OFO

9/23/2017 -14.6% 66.6 65.8 0.8 No OFO

9/24/2017 -15.0% 69.2 69.4 -0.1 No OFO

9/25/2017 -8.3% 72.3 71.9 0.3 Low OFO

9/26/2017 -10.2% 72.3 72.0 0.2 No OFO

9/27/2017 -8.4% 72.9 72.8 0.2 No OFO

9/28/2017 -6.5% 74.0 74.9 -0.9 Low OFO

9/29/2017 -9.8% 75.0 75.2 -0.2 No OFO

9/30/2017 -5.5% 72.6 71.3 1.3 No OFO


High OFOs 4

Note: Low OFOs 5



3.

4.

5.

6.

Daily Core Demand Forecast Performance Report for September 2017Combined SoCalGas and SDG&E















Page 23

Attachment C: Applicants’ Response to SCGC-02



(A.17-10-002)

(2nd DATA REQUEST FROM SOUTHERN CALIFORNIA GENERATION COALITION)

DATE RECEIVED: 1-23-18

DATE RESPONSED: 2-6-18

__________________________________________________________________________

1

QUESTION 2.1: Please provide a copy of the report that SoCalGas has filed with the CPUC Energy Division in compliance with Paragraph 13 of the Second Daily Balancing Settlement in A.15-06-020 for the months of October 2017, November 2017, and December 2017. RESPONSE 2.1:

October 2017:

SoCalGas and

SDG&E Monthly Core Forecasting Report - 201710_Redacted.pdf

November 2017:

SoCalGas and


December 2017:

SoCalGas and


Page 1

November 30, 2017 Mr. Franz Cheng Natural Gas Section, Energy Division California Public Utilities Commission 505 Van Ness Avenue San Francisco, CA 94102 RE: SoCalGas and SDG&E Monthly Core Forecasting Report - October 2017 Dear Mr. Cheng: Enclosed please find the Southern California Gas Company (SoCalGas) and San Diego Gas & Electric Company (SDG&E) Monthly Core Forecasting Report. This monthly report is submitted in compliance with D.16-12-015 and D.17-03-020 for the time period October 1, 2017 – October 31, 2017. The report presents, for each Measurement Day covered by the report, the 7:00 a.m. Demand Forecasting Group core load forecast to estimated actual core usage for the Measurement Day and calculates a percent deviation of each of the demand forecasts relative to estimated actual core usage. Please feel free to contact me if you have any questions regarding this report. Please note that a portion of the data is being provided as Confidential, and a Confidentiality Declaration pursuant to D.16-08-024 accompanies the Report. Sincerely,



Joseph Mock



Tel: 213.244.3718 Fax: 213.244.4957

[email protected]

Page 2



10/1/2017 -1.2% 70.27 70.60 -0.3 No OFO

10/2/2017 -10.3% 68.57 69.70 -1.1 No OFO

10/3/2017 -5.3% 66.67 67.96 -1.3 No OFO

10/4/2017 -1.5% 67.80 68.31 -0.5 No OFO

10/5/2017 -0.2% 69.81 70.21 -0.4 No OFO

10/6/2017 -1.2% 73.75 74.48 -0.7 No OFO

10/7/2017 1.6% 75.93 76.05 -0.1 No OFO

10/8/2017 0.4% 70.34 69.86 0.5 High OFO

10/9/2017 2.9% 71.40 72.91 -1.5 No OFO

10/10/2017 0.6% 69.90 70.77 -0.9 No OFO

10/11/2017 -3.4% 67.84 68.05 -0.2 Low OFO

10/12/2017 -2.5% 67.51 68.27 -0.8 No OFO

10/13/2017 -5.6% 67.80 67.61 0.2 No OFO

10/14/2017 -8.7% 70.95 70.95 0.0 High OFO

10/15/2017 -3.2% 74.54 75.09 -0.5 No OFO

10/16/2017 -3.1% 76.78 77.97 -1.2 Low OFO

10/17/2017 8.3% 76.25 78.18 -1.9 No OFO

10/18/2017 8.1% 75.16 75.51 -0.4 No OFO

10/19/2017 1.0% 69.98 69.79 0.2 No OFO

10/20/2017 -5.9% 66.39 67.79 -1.4 High OFO

10/21/2017 -12.9% 67.08 67.31 -0.2 High OFO

10/22/2017 -0.4% 72.74 73.87 -1.1 High OFO

10/23/2017 7.6% 80.16 80.56 -0.4 Low OFO

10/24/2017 10.0% 83.86 86.91 -3.1 No OFO

10/25/2017 8.0% 81.46 85.61 -4.1 No OFO

10/26/2017 0.0% 75.96 77.73 -1.8 Low OFO

10/27/2017 7.2% 73.51 72.52 1.0 High OFO

10/28/2017 -1.0% 71.70 70.65 1.0 High OFO

10/29/2017 -1.9% 67.47 66.83 0.6 High OFO

10/30/2017 -4.3% 64.72 65.65 -0.9 No OFO

10/31/2017 -0.6% 64.17 64.95 -0.8 High OFO


High OFOs 9

Note: Low OFOs 4



3.

4.

5.

6.

Daily Core Demand Forecast Performance Report for October 2017Combined SoCalGas and SDG&E















Page 3

January 2, 2018 Mr. Franz Cheng Natural Gas Section, Energy Division California Public Utilities Commission 505 Van Ness Avenue San Francisco, CA 94102 RE: SoCalGas and SDG&E Monthly Core Forecasting Report - November 2017 Dear Mr. Cheng: Enclosed please find the Southern California Gas Company (SoCalGas) and San Diego Gas & Electric Company (SDG&E) Monthly Core Forecasting Report. This monthly report is submitted in compliance with D.16-12-015 and D.17-03-020 for the time period November 1, 2017 – November 30, 2017. The report presents, for each Measurement Day covered by the report, the 7:00 a.m. Demand Forecasting Group core load forecast to estimated actual core usage for the Measurement Day and calculates a percent deviation of each of the demand forecasts relative to estimated actual core usage. Please feel free to contact me if you have any questions regarding this report. Please note that a portion of the data is being provided as Confidential, and a Confidentiality Declaration pursuant to D.16-08-024 accompanies the Report. Sincerely,


Jean Spencer, CPUC Energy Division Nika Rodgers, CPUC, ORA Pearlie Sabino, CPUC, ORA

Joseph Mock



Tel: 213.244.3718 Fax: 213.244.4957

[email protected]

Page 4



11/1/2017 6.7% 64.79 66.22 -1.4 High OFO

11/2/2017 11.3% 63.11 63.70 -0.6 High OFO

11/3/2017 15.6% 62.31 63.87 -1.6 High OFO

11/4/2017 7.6% 62.96 63.04 -0.1 High OFO

11/5/2017 1.5% 63.90 64.78 -0.9 High OFO

11/6/2017 6.9% 63.32 64.27 -0.9 Low OFO

11/7/2017 -0.9% 66.43 66.57 -0.1 No OFO

11/8/2017 1.3% 65.48 65.53 0.0 No OFO

11/9/2017 0.1% 65.47 65.65 -0.2 No OFO

11/10/2017 3.5% 63.23 62.95 0.3 High OFO

11/11/2017 -0.8% 62.49 62.39 0.1 High OFO

11/12/2017 -3.6% 62.56 61.40 1.2 No OFO

11/13/2017 -6.9% 63.54 62.79 0.8 No OFO

11/14/2017 -9.1% 65.13 65.08 0.0 Both OFO

11/15/2017 -7.1% 67.07 66.83 0.2 High OFO

11/16/2017 0.7% 68.18 68.01 0.2 High OFO

11/17/2017 2.6% 66.05 67.35 -1.3 High OFO

11/18/2017 -14.5% 64.76 65.01 -0.3 High OFO

11/19/2017 -8.3% 62.67 62.09 0.6 High OFO

11/20/2017 -11.0% 62.80 61.62 1.2 No OFO

11/21/2017 -5.4% 70.46 70.44 0.0 High OFO

11/22/2017 -1.4% 74.95 75.61 -0.7 High OFO

11/23/2017 3.7% 74.69 75.00 -0.3 No OFO

11/24/2017 9.3% 70.53 70.97 -0.4 High OFO

11/25/2017 1.0% 69.45 69.08 0.4 High OFO

11/26/2017 -4.3% 65.38 64.56 0.8 High OFO

11/27/2017 9.2% 60.71 62.17 -1.5 No OFO

11/28/2017 -8.3% 60.77 60.21 0.6 High OFO

11/29/2017 -17.5% 61.87 61.83 0.0 No OFO

11/30/2017 -13.4% 61.59 61.87 -0.3 No OFO


High OFOs 18

Note: Low OFOs 1



3.

4.

5.

6.

Daily Core Demand Forecast Performance Report for November 2017Combined SoCalGas and SDG&E















Page 5

January 31, 2018 Mr. Franz Cheng Natural Gas Section, Energy Division California Public Utilities Commission 505 Van Ness Avenue San Francisco, CA 94102 RE: SoCalGas and SDG&E Monthly Core Forecasting Report - December 2017 Dear Mr. Cheng: Enclosed please find the Southern California Gas Company (SoCalGas) and San Diego Gas & Electric Company (SDG&E) Monthly Core Forecasting Report. This monthly report is submitted in compliance with D.16-12-015 and D.17-11-021 for the time period December 1, 2017 – December 31, 2017. The report presents, for each Measurement Day covered by the report, the 7:00 a.m. Demand Forecasting Group core load forecast to estimated actual core usage for the Measurement Day and calculates a percent deviation of each of the demand forecasts relative to estimated actual core usage. Please feel free to contact me if you have any questions regarding this report. Please note that a portion of the data is being provided as Confidential, and a Confidentiality Declaration pursuant to D.16-08-024 accompanies the Report. Sincerely,



Joseph Mock



Tel: 213.244.3718 Fax: 213.244.4957

[email protected]

Page 6



12/1/2017 8.0% 62.11 62.40 -0.3 High OFO

12/2/2017 3.0% 62.01 63.01 -1.0 High OFO

12/3/2017 8.1% 60.66 60.18 0.5 No OFO

12/4/2017 4.1% 58.23 59.13 -0.9 Low OFO

12/5/2017 -11.3% 58.65 58.21 0.4 Low OFO

12/6/2017 -10.1% 60.77 61.47 -0.7 No OFO

12/7/2017 -10.0% 63.05 65.39 -2.3 Low OFO

12/8/2017 -2.9% 62.80 63.70 -0.9 Low OFO

12/9/2017 -12.0% 64.64 64.44 0.2 High OFO

12/10/2017 -10.0% 66.19 66.65 -0.5 No OFO

12/11/2017 -8.2% 66.28 65.61 0.7 Low OFO

12/12/2017 -10.7% 64.07 63.39 0.7 Low OFO

12/13/2017 -7.8% 62.84 63.26 -0.4 Low OFO

12/14/2017 -5.0% 62.01 60.30 1.7 Low OFO

12/15/2017 -4.2% 63.50 63.57 -0.1 Low OFO

12/16/2017 3.7% 59.58 58.65 0.9 High OFO

12/17/2017 -4.9% 59.52 60.17 -0.6 No OFO

12/18/2017 -3.9% 58.82 57.61 1.2 Low OFO

12/19/2017 -5.3% 57.36 56.91 0.4 Low OFO

12/20/2017 7.9% 53.29 53.57 -0.3 Low OFO

12/21/2017 -5.4% 53.29 52.53 0.8 Low OFO

12/22/2017 -5.1% 51.81 51.44 0.4 Low OFO

12/23/2017 -15.9% 56.02 54.66 1.4 Low OFO

12/24/2017 -10.4% 58.01 58.34 -0.3 Low OFO

12/25/2017 1.1% 56.39 56.31 0.1 Both OFO

12/26/2017 -5.9% 57.08 55.96 1.1 No OFO

12/27/2017 -11.2% 60.21 60.75 -0.5 No OFO

12/28/2017 -10.6% 61.94 62.40 -0.5 No OFO

12/29/2017 -14.2% 64.50 64.48 0.0 No OFO

12/30/2017 -7.9% 60.91 60.05 0.9 No OFO

12/31/2017 -4.0% 59.12 58.82 0.3 No OFO


High OFOs 4

Note: Low OFOs 16



3.

4.

5.

6.

Daily Core Demand Forecast Performance Report for December 2017Combined SoCalGas and SDG&E















Page 7



(A.17-10-002)




__________________________________________________________________________

2

QUESTION 2.2: Please provide, for the months, January 2016 to November 2016, the percentage difference for each day between the core’s daily usage forecast and the core’s recorded daily usage. The response should be based upon the definitions stated in the footnotes to the report that SoCalGas has filed with the CPUC Energy Division in compliance with Paragraph 13 of the Second Daily Balancing Settlement in A.15-06-020. RESPONSE 2.2:

SCGC Q2.2.xlsx

Page 8

(Forecasted - Estimated Recorded)/

Estimated Recorded

Date % Difference

1/1/2016 3.7%

1/2/2016 -5.1%

1/3/2016 0.9%

1/4/2016 18.6%

1/5/2016 23.2%

1/6/2016 -3.4%

1/7/2016 16.7%

1/8/2016 10.6%

1/9/2016 5.3%

1/10/2016 24.0%

1/11/2016 14.7%

1/12/2016 -3.8%

1/13/2016 -2.6%

1/14/2016 4.3%

1/15/2016 3.5%

1/16/2016 5.1%

1/17/2016 -0.2%

1/18/2016 -2.4%

1/19/2016 7.2%

1/20/2016 28.3%

1/21/2016 3.4%

1/22/2016 -3.6%

1/23/2016 7.9%

1/24/2016 10.6%

1/25/2016 0.9%

1/26/2016 2.3%

1/27/2016 -11.7%

1/28/2016 -11.1%

1/29/2016 -5.8%

1/30/2016 -0.5%

1/31/2016 7.8%

2/1/2016 -0.8%

2/2/2016 -7.9%

2/3/2016 -7.1%

2/4/2016 -12.6%

2/5/2016 -13.3%

2/6/2016 -12.4%

2/7/2016 -14.3%

2/8/2016 5.0%

2/9/2016 11.4%

2/10/2016 11.9%

2/11/2016 11.4%

2/12/2016 8.3%

2/13/2016 -0.3%

SCGC Data Request 2.2Combined SoCalGas and SDG&E

1 Page 9

2/14/2016 3.7%

2/15/2016 16.8%

2/16/2016 25.6%

2/17/2016 9.5%

2/18/2016 40.4%

2/19/2016 18.0%

2/20/2016 8.9%

2/21/2016 5.7%

2/22/2016 0.6%

2/23/2016 7.7%

2/24/2016 12.0%

2/25/2016 9.0%

2/26/2016 10.2%

2/27/2016 7.4%

2/28/2016 10.9%

2/29/2016 14.1%

3/1/2016 2.4%

3/2/2016 4.8%

3/3/2016 9.8%

3/4/2016 3.0%

3/5/2016 -0.6%

3/6/2016 34.1%

3/7/2016 14.7%

3/8/2016 -5.0%

3/9/2016 -7.7%

3/10/2016 -7.3%

3/11/2016 8.3%

3/12/2016 0.1%

3/13/2016 0.1%

3/14/2016 8.2%

3/15/2016 -8.0%

3/16/2016 -4.4%

3/17/2016 3.1%

3/18/2016 1.9%

3/19/2016 0.1%

3/20/2016 0.9%

3/21/2016 8.9%

3/22/2016 16.5%

3/23/2016 -3.7%

3/24/2016 -9.3%

3/25/2016 -5.1%

3/26/2016 -3.4%

3/27/2016 0.8%

3/28/2016 43.8%

3/29/2016 3.9%

3/30/2016 10.9%

3/31/2016 -2.7%

4/1/2016 -7.8%

4/2/2016 -12.9%

4/3/2016 -2.9%

4/4/2016 -1.1%2 Page 10

4/5/2016 -0.5%

4/6/2016 3.8%

4/7/2016 -3.3%

4/8/2016 1.5%

4/9/2016 -1.3%

4/10/2016 5.6%

4/11/2016 5.6%

4/12/2016 -2.4%

4/13/2016 1.8%

4/14/2016 0.6%

4/15/2016 -6.2%

4/16/2016 -5.3%

4/17/2016 4.1%

4/18/2016 8.6%

4/19/2016 9.8%

4/20/2016 6.8%

4/21/2016 2.9%

4/22/2016 3.2%

4/23/2016 0.7%

4/24/2016 3.0%

4/25/2016 11.7%

4/26/2016 -2.0%

4/27/2016 -0.6%

4/28/2016 2.0%

4/29/2016 -3.0%

4/30/2016 3.8%

5/1/2016 -7.8%

5/2/2016 -10.9%

5/3/2016 -6.3%

5/4/2016 -3.2%

5/5/2016 2.6%

5/6/2016 -1.9%

5/7/2016 -4.6%

5/8/2016 -7.0%

5/9/2016 -12.9%

5/10/2016 -12.5%

5/11/2016 -10.1%

5/12/2016 -3.0%

5/13/2016 -3.5%

5/14/2016 -2.5%

5/15/2016 -4.2%

5/16/2016 -5.1%

5/17/2016 -7.0%

5/18/2016 -2.8%

5/19/2016 -4.9%

5/20/2016 12.5%

5/21/2016 11.7%

5/22/2016 -0.6%

5/23/2016 -1.9%

5/24/2016 6.3%

5/25/2016 -3.0%3 Page 11

5/26/2016 -7.1%

5/27/2016 -1.0%

5/28/2016 -1.6%

5/29/2016 1.9%

5/30/2016 -4.4%

5/31/2016 6.8%

6/1/2016 -11.0%

6/2/2016 -5.3%

6/3/2016 3.3%

6/4/2016 -3.2%

6/5/2016 1.6%

6/6/2016 -5.7%

6/7/2016 -4.3%

6/8/2016 -6.0%

6/9/2016 -5.6%

6/10/2016 -3.4%

6/11/2016 -11.5%

6/12/2016 -3.6%

6/13/2016 -9.5%

6/14/2016 -11.2%

6/15/2016 -8.3%

6/16/2016 -7.4%

6/17/2016 -0.1%

6/18/2016 0.7%

6/19/2016 4.9%

6/20/2016 16.1%

6/21/2016 9.6%

6/22/2016 8.6%

6/23/2016 11.1%

6/24/2016 8.5%

6/25/2016 10.9%

6/26/2016 19.2%

6/27/2016 14.6%

6/28/2016 16.8%

6/29/2016 14.7%

6/30/2016 3.4%

7/1/2016 -3.1%

7/2/2016 -1.8%

7/3/2016 -0.2%

7/4/2016 1.1%

7/5/2016 -1.8%

7/6/2016 -8.0%

7/7/2016 -6.8%

7/8/2016 -2.2%

7/9/2016 -4.0%

7/10/2016 3.5%

7/11/2016 -2.5%

7/12/2016 -2.8%

7/13/2016 -4.0%

7/14/2016 -1.6%

7/15/2016 -1.2%4 Page 12

7/16/2016 0.1%

7/17/2016 5.6%

7/18/2016 2.9%

7/19/2016 -5.6%

7/20/2016 1.4%

7/21/2016 6.4%

7/22/2016 21.6%

7/23/2016 9.6%

7/24/2016 16.3%

7/25/2016 4.6%

7/26/2016 5.5%

7/27/2016 10.2%

7/28/2016 22.6%

7/29/2016 26.6%

7/30/2016 23.2%

7/31/2016 24.1%

8/1/2016 13.6%

8/2/2016 5.8%

8/3/2016 9.1%

8/4/2016 5.3%

8/5/2016 7.3%

8/6/2016 6.1%

8/7/2016 9.0%

8/8/2016 5.6%

8/9/2016 1.8%

8/10/2016 0.2%

8/11/2016 3.0%

8/12/2016 3.6%

8/13/2016 11.5%

8/14/2016 13.6%

8/15/2016 15.1%

8/16/2016 7.3%

8/17/2016 2.0%

8/18/2016 5.3%

8/19/2016 1.0%

8/20/2016 2.6%

8/21/2016 6.6%

8/22/2016 -0.3%

8/23/2016 2.5%

8/24/2016 -1.0%

8/25/2016 -0.6%

8/26/2016 -6.2%

8/27/2016 -5.8%

8/28/2016 -2.1%

8/29/2016 -2.8%

8/30/2016 3.9%

8/31/2016 5.2%

9/1/2016 3.1%

9/2/2016 0.6%

9/3/2016 -1.3%

9/4/2016 2.3%5 Page 13

9/5/2016 -5.8%

9/6/2016 0.4%

9/7/2016 -5.8%

9/8/2016 -2.2%

9/9/2016 -3.0%

9/10/2016 -4.1%

9/11/2016 -0.1%

9/12/2016 -5.0%

9/13/2016 -11.7%

9/14/2016 -14.5%

9/15/2016 -10.2%

9/16/2016 -9.5%

9/17/2016 -10.0%

9/18/2016 -4.7%

9/19/2016 0.0%

9/20/2016 -0.5%

9/21/2016 -5.7%

9/22/2016 -1.5%

9/23/2016 -8.8%

9/24/2016 -9.0%

9/25/2016 1.0%

9/26/2016 16.5%

9/27/2016 4.9%

9/28/2016 7.0%

9/29/2016 5.6%

9/30/2016 3.2%

10/1/2016 4.0%

10/2/2016 0.6%

10/3/2016 -7.3%

10/4/2016 -5.7%

10/5/2016 -6.5%

10/6/2016 -8.5%

10/7/2016 -4.3%

10/8/2016 0.7%

10/9/2016 1.5%

10/10/2016 0.2%

10/11/2016 -0.9%

10/12/2016 -9.0%

10/13/2016 -7.7%

10/14/2016 -3.7%

10/15/2016 -4.0%

10/16/2016 0.7%

10/17/2016 -2.3%

10/18/2016 -8.2%

10/19/2016 -1.9%

10/20/2016 -2.9%

10/21/2016 1.2%

10/22/2016 -2.4%

10/23/2016 -3.6%

10/24/2016 -7.3%

10/25/2016 -5.5%6 Page 14

10/26/2016 -3.2%

10/27/2016 -7.2%

10/28/2016 0.1%

10/29/2016 -3.4%

10/30/2016 -4.7%

10/31/2016 -2.2%

11/1/2016 17.5%

11/2/2016 4.3%

11/3/2016 12.6%

11/4/2016 15.1%

11/5/2016 11.2%

11/6/2016 7.2%

11/7/2016 10.0%

11/8/2016 11.1%

11/9/2016 18.4%

11/10/2016 26.5%

11/11/2016 18.2%

11/12/2016 14.6%

11/13/2016 17.5%

11/14/2016 13.8%

11/15/2016 10.4%

11/16/2016 4.5%

11/17/2016 3.5%

11/18/2016 -4.9%

11/19/2016 -8.9%

11/20/2016 -0.2%

11/21/2016 8.1%

11/22/2016 1.4%

11/23/2016 -8.1%

11/24/2016 -14.4%

11/25/2016 -12.5%

11/26/2016 -1.8%

11/27/2016 -10.4%

11/28/2016 -6.2%

11/29/2016 -12.1%

11/30/2016 -9.8%

7 Page 15



(A.17-10-002)




__________________________________________________________________________

3

QUESTION 2.3: Please provide, for the years 2016-2017, the percentage difference for each day between the core’s recorded daily usage and the core’s scheduled daily nominations as of Intraday Cycle 2. The percentage difference should be indicated as positive for nominations greater than recorded usage and negative for nominations less than recorded usage. The core’s daily usage should be defined as stated in the footnotes to the report that SoCalGas has filed with the CPUC Energy Division in compliance with Paragraph 13 of the Second Daily Balancing Settlement in A.15-06-020. RESPONSE 2.3:

SoCalGas and SDG&E object to this request on the grounds that an Assigned Commissioner’s Scoping Memo and Ruling has not been issued in this proceeding and therefore this request currently seeks the production of information that is neither relevant to the subject matter involved in the pending proceeding nor is likely reasonably calculated to lead to the discovery of admissible evidence, and is outside the scope of this proceeding as proposed by SoCalGas and SDG&E. Subject to and without waiving these objections, SoCalGas and SDG&E reserve to the right to amend this response should the request ultimately be within the determined scope of this proceeding.

Page 16

Attachment D: Applicants’ Response to SCGC-IS-03

SAN DIEGO GAS & ELECTRIC COMPANY

SOUTHERN CALIFORNIA GAS COMPANY

APPLICATION REGARDING FEASIBILITY OF INCORPORATING

ADVANCED METER DATA INTO THE CORE BALANCING PROCESS

(A.17-10-002)

(3RD DATA REQUEST FROM SOUTHERN CALIFORNIA GENERATION COALITION AND INDICATED SHIPPERS)

__________________________________________________________________________

1

QUESTION 3.1: Please provide a copy of the report that SoCalGas has filed with the CPUC Energy Division in compliance with Paragraph 13 of the Second Daily Balancing Settlement in A.15-06-020 for the months of January 2018, February 2018, March 2018, and April 2018. RESPONSE 3.1:

SCGC 3.1.zip

Page 1

February 28, 2018 Mr. Franz Cheng Natural Gas Section, Energy Division California Public Utilities Commission 505 Van Ness Avenue San Francisco, CA 94102 RE: SoCalGas and SDG&E Monthly Core Forecasting Report - January 2018 Dear Mr. Cheng: Enclosed please find the Southern California Gas Company (SoCalGas) and San Diego Gas & Electric Company (SDG&E) Monthly Core Forecasting Report. This monthly report is submitted in compliance with D.16-12-015 and D.17-11-021 for the time period January 1, 2018 – January 31, 2018. The report presents, for each Measurement Day covered by the report, the 7:00 a.m. Demand Forecasting Group core load forecast to estimated actual core usage for the Measurement Day and calculates a percent deviation of each of the demand forecasts relative to estimated actual core usage. Please feel free to contact me if you have any questions regarding this report. Please note that a portion of the data is being provided as Confidential, and a Confidentiality Declaration pursuant to D.16-08-024 accompanies the Report. Sincerely,



Joseph Mock



Tel: 213.244.3718 Fax: 213.244.4957

[email protected]

Page 2



1/1/2018 4.7% 58.72 57.91 0.8 No OFO

1/2/2018 3.1% 61.67 63.92 -2.2 Low OFO

1/3/2018 7.2% 61.82 62.65 -0.8 No OFO

1/4/2018 11.2% 62.24 62.87 -0.6 No OFO

1/5/2018 19.3% 63.05 63.17 -0.1 No OFO

1/6/2018 17.4% 63.85 62.97 0.9 High OFO

1/7/2018 12.1% 63.93 62.65 1.3 No OFO

1/8/2018 8.5% 63.25 63.49 -0.2 Low OFO

1/9/2018 2.9% 57.84 57.92 -0.1 Low OFO

1/10/2018 9.9% 56.81 56.53 0.3 No OFO

1/11/2018 4.1% 58.89 58.92 0.0 No OFO

1/12/2018 7.6% 61.53 60.96 0.6 High OFO

1/13/2018 -1.2% 64.66 65.65 -1.0 High OFO

1/14/2018 6.5% 65.41 66.52 -1.1 High OFO

1/15/2018 3.1% 61.54 60.97 0.6 High OFO

1/16/2018 11.9% 60.88 60.65 0.2 Low OFO

1/17/2018 5.5% 63.27 63.22 0.1 No OFO

1/18/2018 6.2% 63.69 63.43 0.3 No OFO

1/19/2018 11.2% 59.00 58.66 0.3 Low OFO

1/20/2018 3.9% 55.21 55.58 -0.4 Low OFO

1/21/2018 1.0% 52.57 51.58 1.0 Low OFO

1/22/2018 -5.0% 55.54 54.44 1.1 Low OFO

1/23/2018 -12.9% 59.24 58.48 0.8 Low OFO

1/24/2018 -11.1% 60.41 59.91 0.5 Low OFO

1/25/2018 0.0% 55.13 53.43 1.7 Low OFO

1/26/2018 -3.5% 55.73 55.35 0.4 Low OFO

1/27/2018 -14.8% 58.97 57.57 1.4 Low OFO

1/28/2018 -11.4% 67.51 68.47 -1.0 No OFO

1/29/2018 11.9% 70.41 71.25 -0.8 Low OFO

1/30/2018 8.5% 68.85 68.31 0.5 High OFO

1/31/2018 -2.1% 65.03 64.52 0.5 No OFO


High OFOs 6

Note: Low OFOs 14



3.

4.

5.

6.

Daily Core Demand Forecast Performance Report for January 2018Combined SoCalGas and SDG&E

Confidential and Protected Materials Pursuant to PUC Section 583, GO-66D, and D.17-09-023














Page 3

March 29, 2018 Mr. Franz Cheng Natural Gas Section, Energy Division California Public Utilities Commission 505 Van Ness Avenue San Francisco, CA 94102 RE: SoCalGas and SDG&E Monthly Core Forecasting Report - February 2018 Dear Mr. Cheng: Enclosed please find the Southern California Gas Company (SoCalGas) and San Diego Gas & Electric Company (SDG&E) Monthly Core Forecasting Report. This monthly report is submitted in compliance with D.16-12-015 and D.17-11-021 for the time period February 1, 2018 – February 28, 2018. The report presents, for each Measurement Day covered by the report, the 7:00 a.m. Demand Forecasting Group core load forecast to estimated actual core usage for the Measurement Day and calculates a percent deviation of each of the demand forecasts relative to estimated actual core usage. Please feel free to contact me if you have any questions regarding this report. Please note that a portion of the data is being provided as Confidential, and a Confidentiality Declaration pursuant to D.16-08-024 accompanies the Report. Sincerely,


Jean Spencer, CPUC Energy Division Renee Guild, CPUC Energy Division Nika Rodgers, CPUC, ORA Pearlie Sabino, CPUC, ORA

Joseph Mock



Tel: 213.244.3718 Fax: 213.244.4957

[email protected]

Page 4



2/1/2018 -8.6% 64.80 64.39 0.4 Low OFO

2/2/2018 -5.2% 66.63 66.69 -0.1 No OFO

2/3/2018 -9.0% 66.42 65.30 1.1 No OFO

2/4/2018 -5.6% 66.30 65.87 0.4 No OFO

2/5/2018 2.6% 64.83 63.47 1.4 Low OFO

2/6/2018 2.0% 63.53 62.78 0.7 No OFO

2/7/2018 -8.7% 65.91 65.09 0.8 No OFO

2/8/2018 -4.3% 66.52 65.83 0.7 Low OFO

2/9/2018 -3.4% 64.67 62.87 1.8 No OFO

2/10/2018 18.6% 59.47 59.87 -0.4 High OFO

2/11/2018 0.2% 60.98 59.65 1.3 No OFO

2/12/2018 14.6% 56.31 57.67 -1.4 Low OFO

2/13/2018 1.8% 56.61 56.49 0.1 Low OFO

2/14/2018 3.2% 58.89 60.23 -1.3 Low OFO

2/15/2018 6.4% 58.56 60.91 -2.3 Low OFO

2/16/2018 -6.0% 60.82 61.83 -1.0 Low OFO

2/17/2018 -11.0% 61.37 60.61 0.8 Low OFO

2/18/2018 6.9% 57.92 58.09 -0.2 Low OFO

2/19/2018 0.9% 51.96 53.49 -1.5 Low OFO

2/20/2018 1.0% 49.23 47.71 1.5 Low OFO

2/21/2018 -3.4% 51.03 50.74 0.3 Low OFO

2/22/2018 -5.9% 51.12 50.71 0.4 Low OFO

2/23/2018 -8.4% 51.55 51.61 -0.1 Low OFO

2/24/2018 -4.7% 50.79 49.45 1.3 Low OFO

2/25/2018 -10.0% 54.92 53.70 1.2 Low OFO

2/26/2018 -5.4% 54.64 53.87 0.8 Low OFO

2/27/2018 3.0% 54.15 49.93 4.2 Low OFO

2/28/2018 -0.3% 50.80 50.00 0.8 No OFO


High OFOs 1

Note: Low OFOs 19



3.

4.

5.

6.

Daily Core Demand Forecast Performance Report for February 2018Combined SoCalGas and SDG&E















Page 5

April 30, 2018 Mr. Franz Cheng Natural Gas Section, Energy Division California Public Utilities Commission 505 Van Ness Avenue San Francisco, CA 94102 RE: SoCalGas and SDG&E Monthly Core Forecasting Report - March 2018 Dear Mr. Cheng: Enclosed please find the Southern California Gas Company (SoCalGas) and San Diego Gas & Electric Company (SDG&E) Monthly Core Forecasting Report. This monthly report is submitted in compliance with D.16-12-015 and D.17-11-021 for the time period March 1, 2018 – March 31, 2018. The report presents, for each Measurement Day covered by the report, the 7:00 a.m. Demand Forecasting Group core load forecast to estimated actual core usage for the Measurement Day and calculates a percent deviation of each of the demand forecasts relative to estimated actual core usage. Please feel free to contact me if you have any questions regarding this report. Please note that a portion of the data is being provided as Confidential, and a Confidentiality Declaration pursuant to D.16-08-024 accompanies the Report. Sincerely,



Joseph Mock



Tel: 213.244.3718 Fax: 213.244.4957

[email protected]

Page 6



3/1/2018 -2.3% 53.17 53.17 0.0 Low OFO

3/2/2018 -7.0% 54.77 54.53 0.2 Low OFO

3/3/2018 -1.3% 53.54 55.57 -2.0 Low OFO

3/4/2018 -3.3% 52.72 52.19 0.5 Low OFO

3/5/2018 -16.0% 56.87 56.95 -0.1 Low OFO

3/6/2018 -20.9% 62.07 62.13 -0.1 Low OFO

3/7/2018 -20.7% 61.92 61.18 0.7 Low OFO

3/8/2018 -14.4% 62.53 62.27 0.3 No OFO

3/9/2018 -7.0% 62.84 61.83 1.0 Low OFO

3/10/2018 -5.5% 59.43 59.14 0.3 Low OFO

3/11/2018 -5.8% 61.93 62.10 -0.2 High OFO

3/12/2018 -5.3% 64.06 64.09 0.0 No OFO

3/13/2018 2.5% 62.86 63.91 -1.0 No OFO

3/14/2018 8.1% 58.79 59.80 -1.0 Low OFO

3/15/2018 4.7% 57.21 58.05 -0.8 Low OFO

3/16/2018 -2.8% 55.24 55.13 0.1 Low OFO

3/17/2018 0.9% 55.14 55.31 -0.2 No OFO

3/18/2018 -0.1% 54.37 53.71 0.7 No OFO

3/19/2018 -6.9% 58.53 60.00 -1.5 Low OFO

3/20/2018 -7.9% 61.56 62.31 -0.7 Low OFO

3/21/2018 -11.4% 62.37 61.01 1.4 Low OFO

3/22/2018 -4.3% 61.35 62.19 -0.8 Low OFO

3/23/2018 5.4% 60.09 61.71 -1.6 Low OFO

3/24/2018 -1.5% 58.66 58.40 0.3 Low OFO

3/25/2018 2.8% 56.76 56.79 0.0 Low OFO

3/26/2018 -4.9% 57.76 57.78 0.0 Low OFO

3/27/2018 -12.8% 61.35 61.12 0.2 Low OFO

3/28/2018 -5.3% 63.37 62.69 0.7 Low OFO

3/29/2018 -3.8% 65.96 63.74 2.2 Low OFO

3/30/2018 0.7% 67.13 65.82 1.3 No OFO

3/31/2018 -4.0% 64.66 63.65 1.0 High OFO


High OFOs 2

Note: Low OFOs 23



3.

4.

5.

6.

Daily Core Demand Forecast Performance Report for March 2018Combined SoCalGas and SDG&E















Page 7

May 31, 2018 Mr. Franz Cheng Natural Gas Section, Energy Division California Public Utilities Commission 505 Van Ness Avenue San Francisco, CA 94102 RE: SoCalGas and SDG&E Monthly Core Forecasting Report - April 2018 Dear Mr. Cheng: Enclosed please find the Southern California Gas Company (SoCalGas) and San Diego Gas & Electric Company (SDG&E) Monthly Core Forecasting Report. This monthly report is submitted in compliance with D.16-12-015 and D.17-11-021 for the time period April 1, 2018 – April 30, 2018. The report presents, for each Measurement Day covered by the report, the 7:00 a.m. Demand Forecasting Group core load forecast to estimated actual core usage for the Measurement Day and calculates a percent deviation of each of the demand forecasts relative to estimated actual core usage. Please feel free to contact me if you have any questions regarding this report. Please note that a portion of the data is being provided as Confidential, and a Confidentiality Declaration pursuant to D.16-08-024 accompanies the Report. Sincerely,



Joseph Mock



Tel: 213.244.3718 Fax: 213.244.4957

[email protected]

Page 8

Mdth Mdth % Difference Mdth % Difference degrees F degrees F degrees F

Date Forecast

Core Deliveries (exc.

Net Injections) Deliveries/Forecast Estimated Actual Forecast/Estimated Temp Forecast Temp Actual Forecast Error OFO Status

4/1/2018 -3.3% 62.95 62.43 0.5 No OFO

4/2/2018 -4.2% 61.70 61.99 -0.3 Low OFO

4/3/2018 -10.5% 63.66 63.35 0.3 Low OFO

4/4/2018 -12.5% 63.96 62.18 1.8 No OFO

4/5/2018 -7.6% 63.82 63.01 0.8 No OFO

4/6/2018 -9.4% 64.30 63.53 0.8 No OFO

4/7/2018 -7.6% 66.28 66.35 -0.1 No OFO

4/8/2018 -5.3% 67.00 66.79 0.2 No OFO

4/9/2018 -6.7% 72.09 72.87 -0.8 Low OFO

4/10/2018 12.7% 73.61 73.99 -0.4 Low OFO

4/11/2018 -0.6% 67.95 68.77 -0.8 No OFO

4/12/2018 0.4% 62.57 61.70 0.9 Low OFO

4/13/2018 -13.6% 66.35 65.39 1.0 No OFO

4/14/2018 -7.8% 69.21 69.04 0.2 High OFO

4/15/2018 -1.0% 66.13 66.51 -0.4 High OFO

4/16/2018 11.2% 59.74 59.49 0.3 Low OFO

4/17/2018 -5.1% 60.18 59.01 1.2 Low OFO

4/18/2018 -5.5% 61.56 60.69 0.9 No OFO

4/19/2018 1.6% 58.51 56.91 1.6 Low OFO

4/20/2018 -14.2% 63.09 62.25 0.8 No OFO

4/21/2018 -7.8% 67.82 67.91 -0.1 No OFO

4/22/2018 2.0% 69.97 69.17 0.8 No OFO

4/23/2018 -0.1% 69.19 67.61 1.6 Low OFO

4/24/2018 -10.3% 66.31 64.83 1.5 Low OFO

4/25/2018 3.6% 65.66 64.83 0.8 Low OFO

4/26/2018 3.7% 64.18 64.35 -0.2 Low OFO

4/27/2018 5.3% 63.79 63.23 0.6 High OFO

4/28/2018 -0.6% 63.91 62.79 1.1 High OFO

4/29/2018 12.7% 63.15 62.21 0.9 High OFO

4/30/2018 0.7% 62.66 61.13 1.5 No OFO


High OFOs 5

Note: Low OFOs 12



3.

4.

5.

6.

Daily Core Demand Forecast Performance Report for April 2018Combined SoCalGas and SDG&E


Part of the load forecast error can be explained by the forecast error in temperature provided by the third party vendor.

The Retail Core estimated actual demand for SDG&E is the daily AMI core data (including company use), to which an estimated LUAF has

been added.


Forecast and Estimated Actual data are for retail core (core sales) only and include company use and loss & unaccounted for gas.

The retail core estimated actual demand for SoCalGas is the physical residual after subtracting noncore and core transport agents (CAT)

physical gas demand from the measured daily total system gas sendout, which has been converted to Dth using a 1.0273 MDth/MMcf

heat rate (core average monthly heat rates have ranged from 1.02 to 1.04 MDth/MMcf). The CAT demand is estimated based on the

historical CAT usage per meter with its meter growth assumption.

Page 9





(A.17-10-002)


__________________________________________________________________________

2

QUESTION 3.2: Please provide, for the period, January 1, 2018 through May 21, 2018, the percentage difference for each day between the core’s recorded daily usage and the core’s scheduled daily nominations as of Intraday Cycle 2. The percentage difference should be indicated as positive for nominations greater than recorded usage and negative for nominations less than recorded usage. The core’s daily usage should be defined as stated in the footnotes to the report that SoCalGas has filed with the CPUC Energy Division in compliance with Paragraph 13 of the Second Daily Balancing Settlement in A.15-06-020. RESPONSE 3.2:

SoCalGas and SDG&E object to this question to the extent it seeks confidential, customer-specific information. Notwithstanding this objection, and subject thereto, SoCalGas responds as follows. As agreed to with SCGC, attached is a summary of the daily percentage difference between retail core’s final daily volumes scheduled to its burn account and the retail core’s estimated recorded daily (midnight to midnight) usage (there is no “recorded” core daily usage) for January 1, 2016- April 30, 2018, separated by winter (November-March) and summer (April-October) months. The daily percentage difference indicates as positive for scheduled volumes greater than estimated usage and negative for scheduled volumes less than estimated usage. The estimated recorded daily usage includes company-use fuel and lost & unaccounted for (LUAF) gas, and is derived from the residual load on the SoCalGas & SDG&E systems by subtracting noncore and estimated core transport agent (CAT) load from the total gas sendout. Changes in system linepack have also not been taken into account. The CAT demand is estimated based on the historical CAT usage per meter with its meter growth assumption. Total system sendout is measured in physical volume and for comparison purposes has been converted to Dth using a 1.0273 Dth/Mcf heat rate. The estimated recorded daily usage has not been adjusted to correct for monthly total differences between MCS and customer billing data.

SCGC 3.2.xlsx

Page 10

SCGC 3.2

-39.6%

-39.5%

-39.5%

-36.3%

-31.4%

-29.6%

-26.8%

-26.2%

-24.5%

-24.1%

-23.6%

-23.2%

-22.7%

-22.5%

-22.4%

-22.3%

-22.0%

-21.9%

-21.2%

-20.7%

-20.7%

-20.7%

-20.5%

-20.5%

-20.4%

-20.4%

-20.1%

-20.0%

-20.0%

-20.0%

-19.7%

-19.7%

-19.3%

-19.1%

-19.1%

-18.9%

-18.4%

-18.2%

-17.1%

-17.0%

-16.9%

-16.7%

-16.3%

-16.2%

-16.0%

Page 11

-16.0%

-16.0%

-16.0%

-15.9%

-15.3%

-15.1%

-15.1%

-15.0%

-15.0%

-14.8%

-14.7%

-14.4%

-14.3%

-14.3%

-14.1%

-14.1%

-14.1%

-14.0%

-14.0%

-13.7%

-13.7%

-13.6%

-13.5%

-13.1%

-13.0%

-13.0%

-13.0%

-13.0%

-12.9%

-12.8%

-12.8%

-12.8%

-12.8%

-12.7%

-12.6%

-12.5%

-12.3%

-12.3%

-12.1%

-11.9%

-11.9%

-11.8%

-11.7%

-11.7%

-11.7%

-11.7%

-11.6%

Page 12

-11.5%

-11.4%

-11.3%

-11.0%

-11.0%

-11.0%

-11.0%

-10.8%

-10.8%

-10.7%

-10.5%

-10.4%

-10.4%

-10.3%

-9.7%

-9.7%

-9.6%

-9.4%

-9.3%

-9.3%

-9.2%

-9.2%

-9.0%

-9.0%

-8.9%

-8.9%

-8.9%

-8.9%

-8.6%

-8.5%

-8.4%

-8.3%

-8.3%

-8.2%

-8.2%

-8.1%

-8.0%

-7.9%

-7.8%

-7.6%

-7.4%

-7.2%

-7.2%

-7.2%

-7.1%

-7.1%

-7.0%

Page 13

-7.0%

-6.9%

-6.9%

-6.8%

-6.8%

-6.7%

-6.6%

-6.5%

-6.5%

-6.4%

-6.4%

-6.4%

-6.3%

-6.2%

-6.1%

-6.1%

-5.9%

-5.7%

-5.7%

-5.7%

-5.6%

-5.6%

-5.6%

-5.6%

-5.5%

-5.5%

-5.4%

-5.4%

-5.4%

-5.3%

-5.3%

-5.2%

-5.2%

-5.2%

-5.2%

-5.2%

-5.1%

-5.0%

-5.0%

-5.0%

-4.8%

-4.7%

-4.6%

-4.5%

-4.3%

-4.3%

-4.2%

Page 14

-4.2%

-4.0%

-4.0%

-3.8%

-3.7%

-3.7%

-3.7%

-3.6%

-3.6%

-3.5%

-3.5%

-3.5%

-3.4%

-3.4%

-3.4%

-3.4%

-3.3%

-3.3%

-3.3%

-3.2%

-3.2%

-3.1%

-3.1%

-3.0%

-3.0%

-3.0%

-3.0%

-2.9%

-2.7%

-2.7%

-2.7%

-2.6%

-2.6%

-2.5%

-2.5%

-2.4%

-2.3%

-2.1%

-2.1%

-2.0%

-2.0%

-2.0%

-1.9%

-1.8%

-1.8%

-1.8%

-1.7%

Page 15

-1.6%

-1.5%

-1.5%

-1.5%

-1.4%

-1.4%

-1.4%

-1.3%

-1.1%

-1.1%

-1.1%

-1.1%

-1.0%

-0.9%

-0.9%

-0.8%

-0.8%

-0.7%

-0.6%

-0.6%

-0.6%

-0.5%

-0.4%

-0.3%

-0.3%

-0.3%

-0.2%

-0.2%

-0.1%

-0.1%

0.0%

0.0%

0.1%

0.1%

0.2%

0.3%

0.4%

0.4%

0.6%

0.7%

0.8%

0.8%

0.9%

1.0%

1.0%

1.1%

1.3%

Page 16

1.3%

1.4%

1.4%

1.4%

1.5%

1.5%

1.5%

1.6%

1.7%

1.8%

1.8%

1.8%

1.9%

1.9%

2.0%

2.0%

2.2%

2.2%

2.3%

2.3%

2.4%

2.5%

2.5%

2.5%

2.7%

2.8%

2.8%

2.8%

2.8%

2.9%

3.0%

3.0%

3.0%

3.0%

3.0%

3.1%

3.1%

3.1%

3.2%

3.2%

3.2%

3.3%

3.5%

3.6%

3.6%

3.7%

3.8%

Page 17

3.8%

3.8%

3.9%

3.9%

4.0%

4.1%

4.2%

4.4%

4.4%

4.6%

4.6%

4.6%

4.7%

4.7%

5.0%

5.1%

5.2%

5.2%

5.3%

5.3%

5.4%

5.4%

5.5%

5.6%

5.7%

5.7%

5.7%

5.8%

5.9%

6.0%

6.2%

6.2%

6.3%

6.3%

6.3%

6.4%

6.4%

6.4%

6.5%

6.5%

6.6%

6.7%

6.9%

7.1%

7.1%

7.2%

7.3%

Page 18

7.3%

7.3%

7.4%

7.4%

7.4%

7.6%

7.6%

7.7%

7.7%

7.8%

7.8%

8.0%

8.0%

8.1%

8.1%

8.2%

8.2%

8.4%

8.7%

8.7%

8.9%

9.0%

9.0%

9.1%

9.3%

9.3%

9.3%

9.3%

9.4%

9.4%

9.4%

9.5%

9.5%

9.8%

9.9%

10.0%

10.1%

10.4%

10.4%

10.5%

10.6%

10.8%

11.0%

11.0%

11.1%

11.1%

11.1%

Page 19

11.9%

12.2%

12.4%

13.2%

13.3%

13.8%

13.9%

13.9%

14.6%

14.8%

15.0%

15.1%

15.8%

15.8%

16.0%

16.3%

16.7%

17.0%

17.2%

17.3%

17.3%

17.5%

17.6%

17.9%

18.0%

18.2%

18.5%

19.1%

19.6%

20.5%

22.8%

23.0%

23.6%

25.5%

25.5%

27.9%

73.0%

Page 20





(A.17-10-002)


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3

QUESTION 3.3: With respect to the testimony of David Mercer at pages 3-4 and the Applicants’ response to SCGC-SEU Data Request 2, Q.2.2.4 that was submitted in A.17-10-007: 3.3.1. Are the MTUs randomly assigned to one of the six data transmittal schedules described in the response to Q.2.2.4?

3.3.2. If the answer to the previous question is “no,” please state the basis upon which the modules are assigned to one of the six data transmittal schedules. 3.3.3. Where does SoCalGas maintain its record of which data transmittal schedule each MTU has been assigned to?

RESPONSE 3.3:

3.3.1. The assigned data transmittal schedule is based on the time that the MTU is provisioned (e.g. installed and activated). An MTU can be provisioned at any time installation activities occur. For example, an MTU provisioned at 8:03am would receive confirmation of network connectivity within minutes of installation and the module’s transmission time would be assigned to 9:00 AM. For network operation purposes, the assignment of the data transmittal schedule is considered random. 3.3.2. See response 3.3.1. 3.3.3. Each individual MTU maintains a record of its data transmittal schedule. The assigned transmittal schedule for each MTU is not stored in any central database or system (such as the Head End or MDMS) as a unique data element. However, the assigned transmittal schedule can be inferred from analyzing MTU transmission records in the Head End.

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QUESTION 3.4: With respect to the statement in the testimony of David Mercer at page 5: “The AMI Load processes all data, including the current day’s data, that has been received up to the process run point.” 3.4.1. Does the statement “all data” in the quoted material refer to data for each day that the MTU has been connected to the AMI system?

3.4.2. If the answer to the previous question is “no,” please define the period to which the statement “all data” corresponds. RESPONSE 3.4:

3.4.1. The term “all data” is referring to the gas interval usage data. The AMI Load Process consumes all new data after the previously run AMI Load process. This may, for example, include any missing data that may have become available after the last AMI load. 3.4.2. See response 3.4.1.

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QUESTION 3.5: With respect to the statement in the testimony of David Mercer at page 4: “The data warehouse load process starts at 5:00 PM and stores data from the previous calendar day” and the Applicants’ response to SCGC-SEU Data Request 2, Q.2.5.4, in A.17-10-007 that states: “Daily, the Data Warehouse initiates several load processes that transfers hourly reads and usage data (in cubic feet, not therms) to the Data Warehouse. This process is complete by 5:00 PM.” 3.5.1. Please state what times during each day the “Data Warehouse initiates several load processes that transfers hourly reads and usage data (in cubic feet, not therms) to the Data Warehouse.” 3.5.2. Each time the Data Warehouse initiates the load processes, is all of the AMI data that is present in the MDMS system for the previous Gas Measurement Day is uploaded to the Data Warehouse or only some portion of the data?

3.5.3. If only some portion of the data is uploaded as described in the previous question, please specify how that portion of the data is determined. 3.5.4. How long does it take to upload the data from the MDMS system to the Data Warehouse?

3.5.5. How long would it take to upload the data from the MDMS system to the Data Warehouse if that data were limited to the hourly reads and usage data for only the previous Measurement Day?

RESPONSE 3.5:

3.5.1. There are currently two scheduled processes that transfer interval gas usage from the MDMS to the Data Warehouse. Both scheduled processes will complete by approximately 5:00 PM.

• The first scheduled Data Warehouse Load process that transfers working interval usage data (in cubic feet) begins at 1:00 PM.

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• The second scheduled Data Warehouse Load process begins at 2:30 PM and transfers hourly interval data in cubic feet that has been through the VEE process. The VEE process runs at noon on newly available data within the MDMS.

3.5.2. At the 1:00 PM Data Warehouse Load process, approximately 90% of the previous day’s data is available in the MDMS. The 1:00 PM Data Warehouse Load process will capture this data and load it into the Data Warehouse. This includes data available via the AMI Load job run at 11:00 AM. At the 2:30 PM Data Warehouse Load process, which includes data available via the VEE job that was run at noon, again approximately 90% of the previous day’s data is available in the MDMS. The 2:30 PM Data Warehouse Load process will capture this data and load it into the Data Warehouse. 3.5.3. See response 3.5.2. 3.5.4. See response 3.5.1. 3.5.5. The Data Warehouse Load process is limited to the hourly reads and usage data for the previous and all prior Measurement Days that were received during the previous day. Limiting the upload process to only the previous Measurement Day would have little impact to process run times because the amount of new data not associated with the Previous Measurement Day is minimal. See also response to 3.5.1.

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QUESTION 3.6: With respect to Figure II-2 in the testimony of David Mercer at page 3: 3.6.1. Please confirm that that during each Measurement Day a data packet (consisting of an anchor read and 11 index counts) from a random number of MTUs is transmitted approximately every 15 minutes via the DCUs to the Head End. 3.6.2. Please confirm that the data described in the previous question would then be transmitted, after approximately 15 minutes, from the Head End, with the index counts converted to cubic feet, to the staging tables until it is time to upload the data to the MDMS. 3.6.3. Does the data from the MTUs include an identification of the date as well as the hour number for each of the 12 hours for which volume in cubic feet is recorded?

3.6.4. Would it be possible to upload partial day data for the current Measurement Day at noon or sometime shortly thereafter from the staging tables directly to the Data Warehouse assuming the appropriate programs were developed?

3.6.5. If the answer to the previous question is “no,” would it be possible to send partial day data for the current Measurement Day to the MDMS at noon or sometime shortly thereafter and then upload that data from the MDMS to the Data Warehouse?

RESPONSE 3.6:

3.6.1. The system is designed such that every 15 minutes the Head End should receive data for approximately 250,000 MTU’s. Therefore, during each Measurement Day, a data packet (consisting of an anchor read and 11 index counts) from a random selection of approximately 250,000 MTUs is transmitted approximately every 15 minutes via the DCU’s to the Head End. 3.6.2. SoCalGas considers the staging tables to be part of the AMI Load Process. While the staging tables may be populated every 15 minutes, other aspects necessary to complete the load process (such as cubic feet conversion and meter to MTU validations) are not run until the times indicated in Figure II-2.

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3.6.3. The time information for date and hour is interpreted from the MTU’s transmission time. However, the MTU does not record data in cubic feet. The data transmitted from the MTU to the Head End is “interval gas usage data” and algorithms (typically within the AMI Load Process) have not yet been run to convert the raw meter read to cubic feet. 3.6.4. When considering a Head End to Data Warehouse interface, it is important to remember that the AMI Load Process (the process that transfers data from Head End to MDMS) includes two additional, important functions: 1) the conversion of meter read data to cubic feet and 2) the verification of the proper MTU to meter asset relationship. These functions are examples of processes and procedures that would need to be replicated in any new Head End to Data Warehouse interface. The Advanced Meter system and interface timings were designed for optimal billing efficiency. Any changes implemented to the current system design would impact other processes and procedures. 3.6.5. The Advanced Meter system and interface timings were designed for optimal billing efficiency. Any changes implemented to the current system design would impact other processes and procedures.

Page 26

Attachment E: Applicants’ Response to SCGC-IS-04



(A.17-10-002)

(DATA REQUEST NO. 4 FROM SOUTHERN CALIFORNIA GENERATION COALITION AND INDICATED SHIPPERS)

__________________________________________________________________________

1

QUESTION 4.1: Regarding the Direct Testimony of Sharim Chaudhury at page 2 that states: “SDG&E has completed its AMI system installation for its retail core customers and sufficient historical AMI-based consumption data is available for SDG&E retail core customers.” 4.1.1. Why does the witness characterize SDG&E’s AMI system being installed for its “retail

core customers”? 4.1.2. Does SDG&E exclude customers that are served by a CAT other than Gas Acquisition

from being metered by its AMI system? 4.1.3. If the answer to the previous question is “yes,” please state on what ground SDG&E

excludes customers served by a CAT from its AMI system. 4.1.4. Does SDG&E provide AMI data for the customers served by each CAT to the CAT if

requested and if authorized by the customers? 4.1.5. If the answer to the previous question is “yes,” please explain the procedures that

have been set up to provide AMI data to CATs. 4.1.6. How many core meters does SDG&E meter in total? 4.1.7. How many core meters does SDG&E meter in total through its AMI system? 4.1.8. How many core meters does SDG&E meter through its AMI system that are served by

CATs? RESPONSE 4.1:

4.1.1: The relevant customer data for daily core load forecasting is for retail core customers

because Gas Acquisition is responsible for purchasing gas for retail core customers.

4.1.2: No.

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4.1.3: N/A.

4.1.4: No such requests from core transportation agents (CTAs) have been received by

SDG&E.

4.1.5: N/A.

4.1.6: SDG&E total core meter count including CTAs was 891,197 at the end of 2017.

4.1.7: SDG&E total AMI core meter count including CTAs was 886,752 at the end of 2017.

4.1.8: The total number of core meters in SDG&E’s AMI system that were served by CTAs

was 3,502 at the end of 2017.

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QUESTION 4.2: With respect to the Direct Testimony of Sharim Chaudhury at page 3 that states: To arrive at the final retail core demand numbers, daily SDG&E Company-use gas and estimates of LUAF gas are added to the AMI-based usage numbers.” 4.2.1. Is the company-use and LUAF gas figures added to the AMI-based usage numbers

because the SoCalGas figures are derived residually by subtracting noncore customer usage and CAT customer usage from the measured daily total system gas sendout, a figure that includes company-use and LUAF gas?

4.2.2. If the answer to the previous question is “no,” please explain why the company-use

and LUAF gas are added to the AMI-based usage figures, RESPONSE 4.2:

4.2.1: No, the residual derivation referenced is not applicable to SDG&E’s retail core demand

data. The Gas Acquisition department is responsible for procuring gas for company-use and

LUAF, in addition to gas for retail core customers. Therefore, gas usage data for company-

use gas and LUAF gas are added to arrive at data that represents the amount of gas that the

Gas Acquisition department is responsible for procuring.

4.2.2: See response to 4.2.1.

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QUESTION 4.3: With respect to the Direct Testimony of Sharim Chaudhury at page 4 that states: “cold weather is generally quantified by system-wide heating degree days (“HDDs”), weighted by customer counts.” 4.3.1. Are the customer counts the count of the number of customers that are associated

with each of the twelve weather stations? 4.3.2. From what data source are the customer counts compiled? 4.3.3. How are the areas associated with each weather station delineated? RESPONSE 4.3:

4.3.1 No. Nine weather stations are mapped to six temperature zones for SoCalGas and

three weather stations are mapped to two temperature zones for SDG&E. The customer

counts are used to calculate the weight given to each temperature zone.

4.3.2 Customer counts are compiled from SoCalGas’ monthly billing data.

4.3.3 N/A.

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QUESTION 4.4: With respect to the Direct Testimony of Sharim Chaudhury at page 4 that states: “Manual adjustments to forecasts based on forecasting experience oftentimes can improve upon the forecasts produced by a forecasting model. The daily retail core demand forecasts are tracked and reviewed regularly. After review, the forecasts produced by the DLFM are sometimes adjusted by the Demand Forecasting Group if it determines that the accuracy of future forecasts will likely be improved.” 4.4.1. What factors would the Demand Forecasting Group consider in determining whether to

make a manual adjustment to a forecast? 4.4.2. If the Demand Forecasting Group makes a manual adjustment to a forecast when

would that manual adjustment typically be made? RESPONSE 4.4:

4.4.1: Typical factors the Demand Forecasting group considers in determining whether to make a manual adjustment of the forecast are if recent weather forecasts show a pattern of deviation from the actual weather or if recent daily demand forecasts show a pattern of deviation from actual usage or estimated actual usage. 4.4.2: Manual adjustments are typically made on the day before the next flow day.

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QUESTION 4.5: With respect to the Direct Testimony of Sharim Chaudhury at page 3 that states: “for SDG&E, actual aggregated daily retail core demand data can be derived for recent years from the customer-specific data that have been collected through SDG&E’s AMI system. Pursuant to D.16-12-015, since December 1, 2016, this AMI data has been used in the forecasting process for SDG&E by developing a forecasting model using historical AMI data from October 1, 2013 through September 30, 2016 for all SDG&E retail core customers.” 4.5.1. Has the forecasting model been updated since December 1, 2016, to incorporate

SDG&E AMI metering data for a longer period, say through September 30, 2017? 4.5.2. If the answer to the previous question is “yes,” how does the MAPE for the updated

forecasting model compare to the MAPE for the forecasting model based on the initial three years’ worth of SDG&E AMI data?

4.5.3. If the answer to Q.4.6.1 is “no,” please explain why the Demand Forecasting Group

has not updated the model to reflect the additional year of data. RESPONSE 4.5:

4.5.1: SDG&E’s forecasting model was updated in 2017 using the three years of data ranging from September 1, 2014 to August 31, 2017. 4.5.2: The MAPE for the DLFM based on SDG&E AMI metering data for a longer period has not been calculated. 4.5.3: Assuming this request refers to the answer provided in Q.4.5.1, the response is as follows: N/A.

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QUESTION 4.6: Regarding the Direct Testimony of Sharim Chaudhury at page 9 that states: “some areas of SoCalGas’ service territory still do not have advanced meter coverage. Without the AMI installations completed in all areas, it is not possible to accurately measure SoCalGas’ total actual daily retail core gas usage.” Citing to the August 2017 AMI Semiannual Report. 4.6.1 Please identify the specific information in the August 2017 AMI Semiannual Report

that was relied upon in making the quoted statement. 4.6.2 Would the same statement would be made if the witness were relying upon the

February 2018 AMI Semiannual Report? 4.6.3 If the answer to the previous question is “yes,” please identify the specific information

in the February 2018 AMI Semiannual Report that was relied upon in making the quoted statement.

4.6.4 How many active core meters existed on the SoCalGas system as of December 31,

2017? 4.6.5 Does the witness believe that 100 percent of the SoCalGas meters must be served by

AMI before the SoCalGas AMI data can be incorporated into the forecasting process? 4.6.6 If the answer to the previous question is “no,” please state the percentage penetration

of AMI meters that the witness believes is necessary before the SoCalGas AMI data can be incorporated into the forecasting process.

4.6.7 Please state any other factors that must be addressed before the SoCalGas AMI data

can be incorporated into the forecast. RESPONSE 4.6:

4.6.1: The specific information in the August 2017 AMI Semiannual Report that was relied

upon in making the quoted statement is that AMI installation was not complete at that time.

Please see page 6 of the August 2017 AMI Semiannual Report as an example.

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4.6.2: The statement remains accurate when considering the February 2018 AMI

Semiannual Report.

4.6.3: See the February 2018 AMI Semiannual Report at 4-5.

4.6.4: SoCalGas active core meter count was 5,757,326 as of December 31, 2017.

4.6.5: The witness does not believe that 100 percent of the SoCalGas meters must be

served by AMI before the SoCalGas AMI data can be incorporated into the forecasting

process because there are some customers with meters who have opted out of AMI meters.

4.6.6: The witness believes that the AMI installation should be complete and that sufficient

historical AMI data should be available for SoCalGas’ retail core customers with which to

develop a statistical model.

4.6.7: Regarding the Direct Testimony of Sharim Chaudhury, please see Part IV, section B of

the Direct Testimony of Sharim Chaudhury on pages 9-10.

Page 8



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9

QUESTION 4.7: With respect to the Direct Testimony of Sharim Chaudhury at page 10 that states: “The use of SoCalGas AMI data in the forecasting process is expected to be possible sometime in late 2019 or early 2020.” 4.7.1 Please explain what date the witness is assuming that the SoCalGas AMI system will

be completed. 4.2.2. Please state how many years of SoCalGas AMI data the witness is assuming would

be necessary before the forecast could be based upon SoCalGas AMI data. RESPONSE 4.7:

4.7.1: The witness has not assumed a date of completion for SoCalGas’ AMI system. The witness assumes that the AMI system will be completed in 2018. 4.7.2: As stated in the Direct Testimony of Sharim Chaudhury on page 9, lines 18-19: “After SoCalGas’ AMI system is completely installed, a minimum of one year of historical data is required to estimate the DLFM model parameters.”

Page 9

Attachment F: Applicants’ Response to SCGC-IS-05



(A.17-10-002)

(5th DATA REQUEST FROM SOUTHERN CALIFORNIA GENERATION COALITION AND INDICATED SHIPPERS)

__________________________________________________________________________

1

QUESTION 5.1: Regarding the attachment to the response to data request SCGC-IS-03, Q.3.2, which presented without date identification the percentage difference for each day between the core’s recorded daily usage and the core’s scheduled daily nominations as of Intraday Cycle 2 for the period, January 1, 2016 through April 30, 2018:

5.1.1. Please provide for the period, January 1, 2016 through April 30, 2018, the percentage difference for each day between the core’s recorded daily usage and the core’s scheduled daily nominations as of Intraday Cycle 2 for those days for which a low OFO was declared. All low OFO days should be included regardless of whether noncompliance charges were waived.

5.1.2. Please provide for the period, January 1, 2016 through April 30, 2018, the percentage difference for each day between the core’s recorded daily usage and the core’s scheduled daily nominations as of Intraday Cycle 2 for those days for which a high OFO was declared.

5.1.3. For those days where both a low OFO and a high OFO were declared, the percentage difference between the core’s recorded daily usage and the core’s scheduled daily nominations as of Intraday Cycle 2 should be categorized with the second type of OFO that was declared during the day rather than with the first type of OFO that was declared.

RESPONSE 5.1:

Attached is a summary of the daily percentage difference between retail core’s final daily volumes scheduled to its burn account and the retail core’s estimated recorded daily (midnight to midnight) usage (there is no “recorded” core daily usage) for January 1, 2016- April 30, 2018, separated by high OFO days and low OFO days. The daily percentage difference indicates as positive for scheduled volumes greater than estimated usage and negative for scheduled volumes less than estimated usage. All low OFO days have been included regardless of whether noncompliance charges were waived. For those days where both a low OFO and a high OFO were declared, the percentage difference between the should be categorized with the second type of OFO that was declared during the day. The estimated recorded daily usage includes company-use fuel and lost & unaccounted for (LUAF) gas, and is derived from the residual load on the SoCalGas & SDG&E systems by subtracting noncore and estimated core transport agent (CAT) load from the total gas sendout. Changes in system linepack have also not been taken into account. The CAT

Page 1



(A.17-10-002)


__________________________________________________________________________

2

demand is estimated based on the historical CAT usage per meter with its meter growth assumption. Total system sendout is measured in physical volume and for comparison purposes has been converted to Dth using a 1.0273 Dth/Mcf heat rate. The estimated recorded daily usage has not been adjusted to correct for monthly total differences between MCS and customer billing data.

SCGC 5.1.xlsx

Page 2

SCGC 5.1 High OFOs

27.9%

27.5%

25.1%

24.3%

21.6%

21.0%

20.0%

19.9%

19.0%

18.8%

18.0%

17.9%

17.7%

17.3%

17.1%

16.9%

16.4%

16.3%

16.2%

15.8%

15.1%

15.0%

14.7%

14.1%

13.5%

13.1%

12.6%

12.3%

11.9%

11.9%

11.8%

11.7%

11.7%

11.5%

11.3%

11.3%

11.0%

10.9%

10.6%

10.6%

10.4%

10.2%

10.0%

9.9%

9.6%

Page 3

9.5%

9.4%

9.4%

9.3%

9.3%

9.1%

9.0%

8.9%

8.9%

8.3%

8.2%

8.2%

8.1%

8.1%

7.9%

7.8%

7.7%

7.7%

7.6%

7.4%

7.3%

7.2%

7.1%

7.1%

7.1%

7.0%

6.6%

6.6%

6.5%

6.4%

6.3%

6.2%

6.2%

5.8%

5.6%

5.6%

5.5%

5.4%

5.2%

5.1%

4.7%

4.7%

4.6%

4.5%

4.5%

4.4%

4.1%

Page 4

4.0%

3.9%

3.8%

3.8%

3.6%

3.5%

3.3%

3.2%

3.1%

3.1%

3.0%

3.0%

3.0%

3.0%

2.9%

2.8%

2.8%

2.8%

2.7%

2.5%

2.5%

2.3%

2.0%

1.8%

1.8%

1.7%

1.6%

1.5%

1.5%

1.4%

1.3%

0.8%

0.8%

0.3%

0.2%

0.1%

0.0%

0.0%

-0.1%

-0.3%

-0.6%

-0.6%

-0.7%

-0.9%

-1.1%

-1.2%

-1.3%

Page 5

-1.4%

-1.4%

-1.5%

-1.5%

-1.5%

-1.7%

-1.9%

-2.0%

-2.2%

-2.3%

-2.5%

-2.5%

-2.7%

-2.7%

-3.0%

-3.1%

-3.4%

-3.4%

-3.4%

-3.5%

-3.5%

-3.6%

-3.6%

-3.7%

-3.8%

-4.1%

-4.5%

-4.7%

-5.0%

-5.2%

-5.2%

-5.2%

-5.4%

-5.4%

-5.4%

-5.6%

-5.6%

-5.7%

-5.7%

-5.7%

-6.3%

-6.4%

-6.4%

-6.6%

-6.9%

-7.0%

-7.2%

Page 6

-7.2%

-7.2%

-7.6%

-7.6%

-7.7%

-8.1%

-8.3%

-8.4%

-8.9%

-8.9%

-9.0%

-9.1%

-9.2%

-9.3%

-9.7%

-10.2%

-10.3%

-11.7%

-11.8%

-11.9%

-12.1%

-12.7%

-12.8%

-12.8%

-12.8%

-12.9%

-13.0%

-14.1%

-14.1%

-15.1%

-16.1%

-16.9%

-18.4%

-20.0%

-20.7%

-21.2%

-24.5%

Page 7

SCGC 5.1 Low OFOs

-23.6%

-22.7%

-17.0%

-16.3%

-16.0%

-15.3%

-15.2%

-15.2%

-15.1%

-15.0%

-14.7%

-14.0%

-14.0%

-13.9%

-13.1%

-13.0%

-12.0%

-11.4%

-11.2%

-11.0%

-11.0%

-10.8%

-10.7%

-10.6%

-10.5%

-10.4%

-10.4%

-10.3%

-9.7%

-9.4%

-9.4%

-9.4%

-9.1%

-9.1%

-9.1%

-8.8%

-8.8%

-8.6%

-8.5%

-8.2%

-8.2%

-8.2%

-8.1%

-7.8%

-7.7%

Page 8

-7.7%

-7.6%

-7.6%

-7.5%

-7.5%

-7.5%

-7.3%

-7.2%

-7.2%

-7.2%

-7.1%

-6.9%

-6.8%

-6.7%

-6.6%

-6.5%

-6.5%

-6.5%

-6.4%

-6.1%

-6.1%

-5.9%

-5.8%

-5.6%

-5.5%

-5.4%

-5.3%

-5.3%

-5.2%

-5.1%

-5.0%

-5.0%

-4.9%

-4.9%

-4.9%

-4.8%

-4.7%

-4.7%

-4.4%

-4.2%

-4.0%

-4.0%

-3.9%

-3.7%

-3.7%

-3.7%

-3.3%

Page 9

-3.3%

-3.2%

-3.0%

-3.0%

-2.9%

-2.6%

-2.5%

-2.4%

-2.4%

-2.3%

-2.3%

-2.1%

-2.1%

-2.1%

-2.0%

-1.9%

-1.9%

-1.8%

-1.8%

-1.3%

-1.3%

-1.0%

-1.0%

-1.0%

-0.9%

-0.9%

-0.9%

-0.9%

-0.9%

-0.8%

-0.8%

-0.7%

-0.6%

-0.5%

-0.3%

-0.3%

-0.2%

0.0%

0.1%

0.2%

0.4%

0.5%

0.6%

0.7%

1.0%

1.1%

1.1%

Page 10

1.1%

1.2%

1.3%

1.5%

1.8%

1.8%

1.9%

2.1%

2.8%

2.8%

2.9%

2.9%

2.9%

3.0%

3.1%

3.5%

3.6%

3.7%

4.4%

4.6%

4.6%

4.8%

5.3%

5.4%

5.6%

5.7%

5.9%

6.0%

6.4%

6.5%

6.9%

6.9%

7.2%

7.4%

7.5%

8.0%

8.2%

8.7%

8.7%

9.0%

9.3%

9.6%

9.9%

10.0%

10.0%

10.1%

10.1%

Page 11

10.2%

10.4%

10.4%

11.0%

11.1%

11.1%

11.9%

12.2%

12.4%

12.7%

13.9%

13.9%

14.7%

15.8%

16.0%

16.6%

17.2%

17.3%

17.5%

18.7%

18.8%

19.1%

19.4%

19.6%

20.5%

22.8%

23.0%

25.5%

27.5%

52.9%

73.0%

106.4%

Page 12

Attachment G: Applicants’ Response to SCGC-IS-06



(A.17-10-002)


__________________________________________________________________________

1

QUESTION 6.1: Please provide for the period, January 1, 2016 through April 30, 2018, the percentage difference for each day between the total of all noncore customers’ recorded daily usage and the total of all noncore customers’ scheduled daily nominations as of Intraday Cycle 4 with the date for each difference identified.

RESPONSE 6.1: Please see the attached. The percentage error calculation is (Scheduled Volumes – Usage) / Usage. The data used to calculate the percentage errors is operational data from SoCalGas’ Electronic Bulletin Board, SoCalGas ENVOY®.

SCGC-IS-06.xlsx

Page 1

Flow Date Percent Error Flow Date Percent Error Flow Date Percent Error

1/1/2016 6% 1/1/2017 21% 1/1/2018 17%

1/2/2016 2% 1/2/2017 6% 1/2/2018 4%

1/3/2016 -2% 1/3/2017 -11% 1/3/2018 -8%

1/4/2016 -7% 1/4/2017 -19% 1/4/2018 -3%

1/5/2016 1% 1/5/2017 -6% 1/5/2018 -5%

1/6/2016 -8% 1/6/2017 -25% 1/6/2018 -9%

1/7/2016 -5% 1/7/2017 -3% 1/7/2018 -1%

1/8/2016 -3% 1/8/2017 -4% 1/8/2018 5%

1/9/2016 -3% 1/9/2017 4% 1/9/2018 1%

1/10/2016 4% 1/10/2017 -14% 1/10/2018 6%

1/11/2016 -13% 1/11/2017 -10% 1/11/2018 -7%

1/12/2016 -10% 1/12/2017 -1% 1/12/2018 -12%

1/13/2016 -3% 1/13/2017 -17% 1/13/2018 -2%

1/14/2016 3% 1/14/2017 -1% 1/14/2018 -4%

1/15/2016 -9% 1/15/2017 6% 1/15/2018 -12%

1/16/2016 -2% 1/16/2017 4% 1/16/2018 -6%

1/17/2016 8% 1/17/2017 3% 1/17/2018 2%

1/18/2016 -12% 1/18/2017 -8% 1/18/2018 1%

1/19/2016 -24% 1/19/2017 0% 1/19/2018 3%

1/20/2016 -13% 1/20/2017 -14% 1/20/2018 14%

1/21/2016 -5% 1/21/2017 -10% 1/21/2018 9%

1/22/2016 -9% 1/22/2017 -2% 1/22/2018 4%

1/23/2016 -5% 1/23/2017 9% 1/23/2018 2%

1/24/2016 8% 1/24/2017 8% 1/24/2018 1%

1/25/2016 -12% 1/25/2017 5% 1/25/2018 2%

1/26/2016 10% 1/26/2017 3% 1/26/2018 4%

1/27/2016 -1% 1/27/2017 6% 1/27/2018 3%

1/28/2016 8% 1/28/2017 2% 1/28/2018 3%

1/29/2016 -10% 1/29/2017 1% 1/29/2018 -2%

1/30/2016 2% 1/30/2017 2% 1/30/2018 -8%

1/31/2016 1% 1/31/2017 -4% 1/31/2018 -11%

2/1/2016 7% 2/1/2017 3% 2/1/2018 11%

2/2/2016 -3% 2/2/2017 8% 2/2/2018 0%

2/3/2016 14% 2/3/2017 5% 2/3/2018 0%

2/4/2016 15% 2/4/2017 6% 2/4/2018 -1%

2/5/2016 24% 2/5/2017 -3% 2/5/2018 -2%

2/6/2016 12% 2/6/2017 -7% 2/6/2018 -1%

2/7/2016 7% 2/7/2017 4% 2/7/2018 -14%

2/8/2016 -13% 2/8/2017 -7% 2/8/2018 1%

2/9/2016 -4% 2/9/2017 -10% 2/9/2018 -3%

2/10/2016 -4% 2/10/2017 -5% 2/10/2018 -12%

2/11/2016 -8% 2/11/2017 -9% 2/11/2018 -8%

2/12/2016 -8% 2/12/2017 -7% 2/12/2018 -11%

2/13/2016 -15% 2/13/2017 -4% 2/13/2018 -5%

2/14/2016 11% 2/14/2017 1% 2/14/2018 6%

2/15/2016 -3% 2/15/2017 -8% 2/15/2018 9%

Page 2

2/16/2016 -12% 2/16/2017 -5% 2/16/2018 4%

2/17/2016 -6% 2/17/2017 3% 2/17/2018 0%

2/18/2016 -11% 2/18/2017 2% 2/18/2018 16%

2/19/2016 -12% 2/19/2017 8% 2/19/2018 0%

2/20/2016 -11% 2/20/2017 -7% 2/20/2018 1%

2/21/2016 2% 2/21/2017 -7% 2/21/2018 21%

2/22/2016 -17% 2/22/2017 -5% 2/22/2018 25%

2/23/2016 -8% 2/23/2017 -1% 2/23/2018 8%

2/24/2016 -4% 2/24/2017 -2% 2/24/2018 17%

2/25/2016 -7% 2/25/2017 -3% 2/25/2018 21%

2/26/2016 4% 2/26/2017 1% 2/26/2018 14%

2/27/2016 -11% 2/27/2017 0% 2/27/2018 4%

2/28/2016 7% 2/28/2017 7% 2/28/2018 -13%

2/29/2016 -22% 3/1/2017 1% 3/1/2018 4%

3/1/2016 10% 3/2/2017 7% 3/2/2018 0%

3/2/2016 6% 3/3/2017 10% 3/3/2018 11%

3/3/2016 7% 3/4/2017 11% 3/4/2018 10%

3/4/2016 -2% 3/5/2017 11% 3/5/2018 7%

3/5/2016 -12% 3/6/2017 -7% 3/6/2018 4%

3/6/2016 6% 3/7/2017 0% 3/7/2018 3%

3/7/2016 6% 3/8/2017 -2% 3/8/2018 4%

3/8/2016 14% 3/9/2017 5% 3/9/2018 5%

3/9/2016 2% 3/10/2017 -4% 3/10/2018 -3%

3/10/2016 1% 3/11/2017 -6% 3/11/2018 -4%

3/11/2016 -6% 3/12/2017 -7% 3/12/2018 -1%

3/12/2016 -8% 3/13/2017 -4% 3/13/2018 -8%

3/13/2016 6% 3/14/2017 -8% 3/14/2018 1%

3/14/2016 -5% 3/15/2017 -11% 3/15/2018 4%

3/15/2016 -1% 3/16/2017 -11% 3/16/2018 0%

3/16/2016 0% 3/17/2017 -10% 3/17/2018 12%

3/17/2016 -10% 3/18/2017 -11% 3/18/2018 3%

3/18/2016 2% 3/19/2017 -4% 3/19/2018 -3%

3/19/2016 -4% 3/20/2017 16% 3/20/2018 -4%

3/20/2016 2% 3/21/2017 -7% 3/21/2018 -7%

3/21/2016 -4% 3/22/2017 -6% 3/22/2018 -1%

3/22/2016 -2% 3/23/2017 -12% 3/23/2018 2%

3/23/2016 3% 3/24/2017 -5% 3/24/2018 5%

3/24/2016 8% 3/25/2017 -3% 3/25/2018 2%

3/25/2016 4% 3/26/2017 0% 3/26/2018 1%

3/26/2016 1% 3/27/2017 16% 3/27/2018 0%

3/27/2016 -2% 3/28/2017 -1% 3/28/2018 2%

3/28/2016 21% 3/29/2017 -5% 3/29/2018 0%

3/29/2016 1% 3/30/2017 -2% 3/30/2018 2%

3/30/2016 -6% 3/31/2017 -6% 3/31/2018 6%

3/31/2016 9% 4/1/2017 -1% 4/1/2018 24%

4/1/2016 6% 4/2/2017 13% 4/2/2018 12%

4/2/2016 -6% 4/3/2017 11% 4/3/2018 5%

Page 3

4/3/2016 3% 4/4/2017 -4% 4/4/2018 5%

4/4/2016 -12% 4/5/2017 3% 4/5/2018 0%

4/5/2016 -1% 4/6/2017 -5% 4/6/2018 -5%

4/6/2016 4% 4/7/2017 -13% 4/7/2018 -2%

4/7/2016 3% 4/8/2017 -1% 4/8/2018 2%

4/8/2016 -4% 4/9/2017 5% 4/9/2018 -14%

4/9/2016 12% 4/10/2017 2% 4/10/2018 3%

4/10/2016 16% 4/11/2017 -3% 4/11/2018 8%

4/11/2016 -5% 4/12/2017 -5% 4/12/2018 10%

4/12/2016 -6% 4/13/2017 4% 4/13/2018 4%

4/13/2016 -2% 4/14/2017 14% 4/14/2018 -11%

4/14/2016 -4% 4/15/2017 -5% 4/15/2018 -2%

4/15/2016 3% 4/16/2017 -1% 4/16/2018 0%

4/16/2016 -5% 4/17/2017 -2% 4/17/2018 2%

4/17/2016 4% 4/18/2017 -4% 4/18/2018 -6%

4/18/2016 -12% 4/19/2017 10% 4/19/2018 0%

4/19/2016 2% 4/20/2017 0% 4/20/2018 5%

4/20/2016 -3% 4/21/2017 -7% 4/21/2018 -1%

4/21/2016 0% 4/22/2017 -7% 4/22/2018 1%

4/22/2016 -2% 4/23/2017 4% 4/23/2018 0%

4/23/2016 11% 4/24/2017 -2% 4/24/2018 11%

4/24/2016 9% 4/25/2017 0% 4/25/2018 4%

4/25/2016 19% 4/26/2017 -1% 4/26/2018 6%

4/26/2016 -2% 4/27/2017 -6% 4/27/2018 -3%

4/27/2016 5% 4/28/2017 -4% 4/28/2018 -1%

4/28/2016 2% 4/29/2017 -1% 4/29/2018 -5%

4/29/2016 2% 4/30/2017 4% 4/30/2018 -8%

4/30/2016 -6% 5/1/2017 1%

5/1/2016 -2% 5/2/2017 -11%

5/2/2016 -8% 5/3/2017 -10%

5/3/2016 -2% 5/4/2017 -1%

5/4/2016 2% 5/5/2017 1%

5/5/2016 18% 5/6/2017 -5%

5/6/2016 -6% 5/7/2017 5%

5/7/2016 -3% 5/8/2017 4%

5/8/2016 22% 5/9/2017 3%

5/9/2016 10% 5/10/2017 1%

5/10/2016 13% 5/11/2017 5%

5/11/2016 -2% 5/12/2017 9%

5/12/2016 3% 5/13/2017 11%

5/13/2016 4% 5/14/2017 13%

5/14/2016 -6% 5/15/2017 -2%

5/15/2016 1% 5/16/2017 1%

5/16/2016 -6% 5/17/2017 5%

5/17/2016 -9% 5/18/2017 7%

5/18/2016 3% 5/19/2017 -1%

5/19/2016 10% 5/20/2017 -1%

Page 4

5/20/2016 -11% 5/21/2017 -3%

5/21/2016 -14% 5/22/2017 -6%

5/22/2016 -3% 5/23/2017 -2%

5/23/2016 2% 5/24/2017 14%

5/24/2016 12% 5/25/2017 -3%

5/25/2016 -3% 5/26/2017 0%

5/26/2016 6% 5/27/2017 3%

5/27/2016 1% 5/28/2017 6%

5/28/2016 -10% 5/29/2017 12%

5/29/2016 3% 5/30/2017 8%

5/30/2016 -4% 5/31/2017 -3%

5/31/2016 7% 6/1/2017 2%

6/1/2016 12% 6/2/2017 6%

6/2/2016 4% 6/3/2017 -5%

6/3/2016 -2% 6/4/2017 3%

6/4/2016 4% 6/5/2017 8%

6/5/2016 16% 6/6/2017 1%

6/6/2016 13% 6/7/2017 0%

6/7/2016 3% 6/8/2017 12%

6/8/2016 10% 6/9/2017 1%

6/9/2016 11% 6/10/2017 11%

6/10/2016 9% 6/11/2017 2%

6/11/2016 9% 6/12/2017 14%

6/12/2016 27% 6/13/2017 -2%

6/13/2016 7% 6/14/2017 -4%

6/14/2016 15% 6/15/2017 5%

6/15/2016 13% 6/16/2017 -2%

6/16/2016 16% 6/17/2017 -1%

6/17/2016 -1% 6/18/2017 -11%

6/18/2016 4% 6/19/2017 0%

6/19/2016 21% 6/20/2017 3%

6/20/2016 15% 6/21/2017 19%

6/21/2016 11% 6/22/2017 6%

6/22/2016 4% 6/23/2017 -5%

6/23/2016 -2% 6/24/2017 -10%

6/24/2016 -5% 6/25/2017 -4%

6/25/2016 4% 6/26/2017 1%

6/26/2016 3% 6/27/2017 -6%

6/27/2016 2% 6/28/2017 -5%

6/28/2016 -3% 6/29/2017 -4%

6/29/2016 10% 6/30/2017 -2%

6/30/2016 6% 7/1/2017 10%

7/1/2016 12% 7/2/2017 5%

7/2/2016 -1% 7/3/2017 -1%

7/3/2016 19% 7/4/2017 1%

7/4/2016 29% 7/5/2017 -4%

7/5/2016 17% 7/6/2017 -1%

Page 5

7/6/2016 12% 7/7/2017 -1%

7/7/2016 7% 7/8/2017 -8%

7/8/2016 -8% 7/9/2017 -5%

7/9/2016 1% 7/10/2017 2%

7/10/2016 9% 7/11/2017 0%

7/11/2016 -7% 7/12/2017 -3%

7/12/2016 10% 7/13/2017 0%

7/13/2016 -12% 7/14/2017 -1%

7/14/2016 6% 7/15/2017 4%

7/15/2016 0% 7/16/2017 -2%

7/16/2016 -10% 7/17/2017 1%

7/17/2016 -1% 7/18/2017 2%

7/18/2016 3% 7/19/2017 10%

7/19/2016 6% 7/20/2017 0%

7/20/2016 6% 7/21/2017 3%

7/21/2016 -6% 7/22/2017 -3%

7/22/2016 13% 7/23/2017 1%

7/23/2016 22% 7/24/2017 2%

7/24/2016 -2% 7/25/2017 -3%

7/25/2016 -3% 7/26/2017 -1%

7/26/2016 3% 7/27/2017 2%

7/27/2016 2% 7/28/2017 3%

7/28/2016 5% 7/29/2017 -6%

7/29/2016 0% 7/30/2017 0%

7/30/2016 7% 7/31/2017 -1%

7/31/2016 -1% 8/1/2017 -2%

8/1/2016 15% 8/2/2017 -7%

8/2/2016 -2% 8/3/2017 -7%

8/3/2016 0% 8/4/2017 10%

8/4/2016 0% 8/5/2017 4%

8/5/2016 1% 8/6/2017 2%

8/6/2016 -5% 8/7/2017 -2%

8/7/2016 1% 8/8/2017 -3%

8/8/2016 11% 8/9/2017 5%

8/9/2016 -1% 8/10/2017 7%

8/10/2016 -10% 8/11/2017 11%

8/11/2016 -3% 8/12/2017 9%

8/12/2016 -12% 8/13/2017 4%

8/13/2016 0% 8/14/2017 13%

8/14/2016 2% 8/15/2017 0%

8/15/2016 7% 8/16/2017 -8%

8/16/2016 -1% 8/17/2017 -3%

8/17/2016 6% 8/18/2017 -1%

8/18/2016 -14% 8/19/2017 1%

8/19/2016 4% 8/20/2017 3%

8/20/2016 -4% 8/21/2017 1%

8/21/2016 -1% 8/22/2017 -9%

Page 6

8/22/2016 10% 8/23/2017 16%

8/23/2016 5% 8/24/2017 1%

8/24/2016 1% 8/25/2017 -2%

8/25/2016 -2% 8/26/2017 4%

8/26/2016 4% 8/27/2017 7%

8/27/2016 -1% 8/28/2017 0%

8/28/2016 0% 8/29/2017 3%

8/29/2016 -5% 8/30/2017 7%

8/30/2016 4% 8/31/2017 3%

8/31/2016 -3% 9/1/2017 1%

9/1/2016 1% 9/2/2017 -7%

9/2/2016 -2% 9/3/2017 0%

9/3/2016 -3% 9/4/2017 5%

9/4/2016 11% 9/5/2017 0%

9/5/2016 7% 9/6/2017 -6%

9/6/2016 1% 9/7/2017 -2%

9/7/2016 -3% 9/8/2017 1%

9/8/2016 -6% 9/9/2017 -3%

9/9/2016 -4% 9/10/2017 -8%

9/10/2016 -15% 9/11/2017 -13%

9/11/2016 -2% 9/12/2017 -7%

9/12/2016 -1% 9/13/2017 3%

9/13/2016 5% 9/14/2017 10%

9/14/2016 1% 9/15/2017 0%

9/15/2016 -1% 9/16/2017 3%

9/16/2016 7% 9/17/2017 21%

9/17/2016 -5% 9/18/2017 7%

9/18/2016 -8% 9/19/2017 17%

9/19/2016 -3% 9/20/2017 13%

9/20/2016 3% 9/21/2017 5%

9/21/2016 -13% 9/22/2017 9%

9/22/2016 -5% 9/23/2017 17%

9/23/2016 3% 9/24/2017 12%

9/24/2016 5% 9/25/2017 0%

9/25/2016 5% 9/26/2017 8%

9/26/2016 -1% 9/27/2017 -2%

9/27/2016 8% 9/28/2017 3%

9/28/2016 -2% 9/29/2017 1%

9/29/2016 -4% 9/30/2017 20%

9/30/2016 1% 10/1/2017 -10%

10/1/2016 -7% 10/2/2017 -6%

10/2/2016 -1% 10/3/2017 6%

10/3/2016 9% 10/4/2017 -4%

10/4/2016 2% 10/5/2017 -3%

10/5/2016 8% 10/6/2017 -10%

10/6/2016 5% 10/7/2017 -3%

10/7/2016 3% 10/8/2017 1%

Page 7

10/8/2016 -3% 10/9/2017 -8%

10/9/2016 1% 10/10/2017 -10%

10/10/2016 3% 10/11/2017 -3%

10/11/2016 -4% 10/12/2017 -2%

10/12/2016 -6% 10/13/2017 3%

10/13/2016 -2% 10/14/2017 -5%

10/14/2016 -12% 10/15/2017 -4%

10/15/2016 -8% 10/16/2017 -16%

10/16/2016 -2% 10/17/2017 -7%

10/17/2016 2% 10/18/2017 1%

10/18/2016 2% 10/19/2017 7%

10/19/2016 7% 10/20/2017 1%

10/20/2016 6% 10/21/2017 1%

10/21/2016 -7% 10/22/2017 8%

10/22/2016 -7% 10/23/2017 -7%

10/23/2016 -6% 10/24/2017 -7%

10/24/2016 -3% 10/25/2017 -16%

10/25/2016 -8% 10/26/2017 2%

10/26/2016 -1% 10/27/2017 -6%

10/27/2016 -6% 10/28/2017 -8%

10/28/2016 -9% 10/29/2017 -3%

10/29/2016 -13% 10/30/2017 11%

10/30/2016 -1% 10/31/2017 -1%

10/31/2016 30% 11/1/2017 -6%

11/1/2016 -17% 11/2/2017 -8%

11/2/2016 -14% 11/3/2017 -6%

11/3/2016 -1% 11/4/2017 5%

11/4/2016 -8% 11/5/2017 4%

11/5/2016 -6% 11/6/2017 2%

11/6/2016 -1% 11/7/2017 -1%

11/7/2016 -1% 11/8/2017 0%

11/8/2016 -2% 11/9/2017 13%

11/9/2016 -8% 11/10/2017 -10%

11/10/2016 -5% 11/11/2017 -9%

11/11/2016 -5% 11/12/2017 -1%

11/12/2016 -5% 11/13/2017 -2%

11/13/2016 -1% 11/14/2017 4%

11/14/2016 3% 11/15/2017 5%

11/15/2016 -3% 11/16/2017 -5%

11/16/2016 -11% 11/17/2017 1%

11/17/2016 -4% 11/18/2017 0%

11/18/2016 3% 11/19/2017 9%

11/19/2016 -8% 11/20/2017 11%

11/20/2016 11% 11/21/2017 2%

11/21/2016 20% 11/22/2017 3%

11/22/2016 -1% 11/23/2017 15%

11/23/2016 12% 11/24/2017 4%

Page 8

11/24/2016 7% 11/25/2017 2%

11/25/2016 12% 11/26/2017 4%

11/26/2016 13% 11/27/2017 25%

11/27/2016 15% 11/28/2017 0%

11/28/2016 24% 11/29/2017 14%

11/29/2016 21% 11/30/2017 10%

11/30/2016 13% 12/1/2017 1%

12/1/2016 8% 12/2/2017 0%

12/2/2016 3% 12/3/2017 22%

12/3/2016 7% 12/4/2017 11%

12/4/2016 11% 12/5/2017 13%

12/5/2016 6% 12/6/2017 2%

12/6/2016 8% 12/7/2017 1%

12/7/2016 -4% 12/8/2017 18%

12/8/2016 2% 12/9/2017 6%

12/9/2016 -5% 12/10/2017 20%

12/10/2016 0% 12/11/2017 9%

12/11/2016 4% 12/12/2017 5%

12/12/2016 2% 12/13/2017 12%

12/13/2016 -8% 12/14/2017 7%

12/14/2016 -2% 12/15/2017 9%

12/15/2016 -3% 12/16/2017 0%

12/16/2016 0% 12/17/2017 20%

12/17/2016 1% 12/18/2017 4%

12/18/2016 4% 12/19/2017 1%

12/19/2016 13% 12/20/2017 6%

12/20/2016 7% 12/21/2017 4%

12/21/2016 2% 12/22/2017 6%

12/22/2016 -16% 12/23/2017 9%

12/23/2016 3% 12/24/2017 19%

12/24/2016 24% 12/25/2017 4%

12/25/2016 21% 12/26/2017 0%

12/26/2016 -3% 12/27/2017 10%

12/27/2016 8% 12/28/2017 -6%

12/28/2016 9% 12/29/2017 -10%

12/29/2016 9% 12/30/2017 7%

12/30/2016 -5% 12/31/2017 8%

12/31/2016 2%

Page 9

Attachment H: 2016 California Gas Report—excerpt

2 0 1 6 C A L I F O R N I A G A S R E P O R T

PREPARED BY THE CALIFORNIA GAS AND ELECTRIC UTILITIES

Southern California Gas Company Pacific Gas and Electric Company

San Diego Gas & Electric Company Southwest Gas Corporation

City of Long Beach Gas & Oil Department Southern California Edison Company

Page 1


20192

PEAK DAY DEMAND AND DELIVERABILITY

Since April 2008, gas supplies to serve both SoCalGas’ and SDG&E’s retail core gas

demand have been procured as a combined portfolio. SoCalGas and SDG&E plan and design

their systems to provide continuous service to their core customers under an extreme peak day event. For each utility’s service area, the extreme peak day is defined as a service area average

temperature so cold that it would, on average, occur only once every 35 years. This definition

translates to a system average temperature of 40.1 degrees Fahrenheit for SoCalGas’ service area and 42.9 degrees Fahrenheit for SDG&E’s service area.

Demand on an extreme peak day is met through a combination of withdrawals from

underground storage facilities and flowing pipeline supplies. The firm storage withdrawal amount of 2,225 MMCF/day is the value SoCalGas and SDG&E are approved to hold (per

CPUC D.08-12-020 on Dec. 4, 2008 at p. 12) to serve the combined core portfolio of SoCalGas’

and SDG&E’s retail core customers. Storage withdrawal plus pipeline supplies must be sufficient to meet peak day operating requirements. The following table provides an

illustration of how storage and flowing supplies can meet forecasted retail core peak day

demand.

Retail Core Peak Day Demand and Supply Requirements

(MMcf/Day)4

Year SoCalGas Retail Core Demand (1)

SDG&E Retail Core Demand (2)

Total Demand

Firm Storage Withdrawal (3)

Flowing Supply

2016 2,947 387 3,334 2,225 1,109

2017 2,944 395 3,339 2,225 1,114

2018 2,931 396 3,326 2,225 1,101

2019 2,917 395 3,312 2,225 1,087

2020 2,899 396 3,294 2,225 1,069

2021 2,875 394 3,270 2,225 1,045

2022 2,849 393 3,242 2,225 1,017

Notes: (1) 1-in-35 peak temperature cold day SoCalGas core sales and transportation. (2) 1-in-35 peak temperature cold day SDG&E core sales and transportation. (3) This amount was approved by the CPUC for SoCalGas and SDG&E to serve the combined core

portfolio of SoCalGas’ and SDG&E’s retail core customers in CPUC D.08-12-020 on 12/4/2008 at p. 12.

(4) SoCalGas and SDG&E are only obligated to design their systems to maintain service to retail and wholesale core customers during a 1-in-35 winter peak day temperature event .

Page 2


93

The tables below provide system-wide Winter (December month) peak day demand

projections on SoCalGas’ system and High Sendout demand during Summer (July, August or September month as designated) periods.

Winter Peak Day Demand

(MMcf/Day)

Year Core (1) Noncore NonEG (2)

Electric Generation (3)

Total Demand

2016 2,947 1,012 1,054 5,013

2017 2,944 1,019 1,051 5,014

2018 2,931 1,019 1,048 4,997

2019 2,917 1,017 1,045 4,978

2020 2,899 1,016 1,042 4,956

2021 2,875 1,009 1,036 4,921

2022 2,849 1,003 1,029 4,882

Notes: (1) 1-in-35 peak temperature cold day for SoCalGas’ core. (2) 1-in-10 peak temperature cold day for HDD-sensitive load. Includes SoCalGas’ non-core and

wholesale non-EG. (3) UEG/EWG Base Hydro + all other EG.

Summer High Sendout Day Demand

(MMcf/Day)

Year High Demand Month (1)

Core (2) Noncore NonEG (3)

Electric Generation (4)

Total Demand

2016 Sep 652 644 2,084 3,380

2017 Sep 653 642 2,005 3,301

2018 Sep 651 641 1,924 3,216

2019 Sep 648 639 1,843 3,130

2020 Sep 644 637 1,773 3,055

2021 Sep 639 633 1,705 2,977

2022 Sep 633 628 1,667 2,928

Notes: (1) Month of High Sendout gas demand during summer (July, August or September). (2) Average daily summer demand SoCalGas core. (3) Average daily summer demand. Includes SoCalGas retail and wholesale load. (4) Highest demand on a summer day under 1-in-10 dry hydro conditions.

Page 3

Attachment I: 2016 California Gas Report—SoCalGas Workpapers

excerpt

2016 CALIFORNIA GAS REPORT

REDACTEDWorkpapers

For External Distribution

Prepared By:

11

1Page 1

Work Paper: TABLE 1-SCG SOUTHERN CALIFORNIA GAS COMPANY

ANNUAL GAS SUPPLY AND REQUIREMENTS - MMCF/DAYESTIMATED FOR YEAR: 2019

AVERAGE TEMPERATURE with BASE HYDRO YEAR

LINE Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Avg LINECAPACITY AVAILABLE

1 California Line 85 Zone (California Producers) 160 160 160 160 160 160 160 160 160 160 160 160 160 12 California Coastal Zone (California Producers) 150 150 150 150 150 150 150 150 150 150 150 150 150 2

Out-of-State Gas

3 Wheeler Ridge Zone (KR, MP, PG&E, OEHI) 1/

765 765 765 765 765 765 765 765 765 765 765 765 765 3

4 Southern Zone (EPN,TGN,NBP) 2/

1,210 1,210 1,210 1,210 1,210 1,210 1,210 1,210 1,210 1,210 1,210 1,210 1,210 4

5 Northern Zone (TW,EPN,QST, KR) 3/

1,590 1,590 1,590 1,590 1,590 1,590 1,590 1,590 1,590 1,590 1,590 1,590 1,590 56 Total Out-of-State Gas 3,565 3,565 3,565 3,565 3,565 3,565 3,565 3,565 3,565 3,565 3,565 3,565 3,565 6

7 TOTAL CAPACITY AVAILABLE 3,875 3,875 3,875 3,875 3,875 3,875 3,875 3,875 3,875 3,875 3,875 3,875 3,875 7

GAS SUPPLY TAKEN8 California Source Gas 122 122 122 122 122 122 122 122 122 122 122 122 122 89 Out-of-State 2,990 2,894 2,498 2,324 2,058 2,047 2,243 2,253 2,413 2,305 2,489 3,019 2,459 910 TOTAL SUPPLY TAKEN 3,112 3,016 2,620 2,446 2,180 2,169 2,365 2,375 2,535 2,427 2,611 3,141 2,581 10

11 Net Underground Storage Withdrawal 0 0 0 0 0 0 0 0 0 0 0 0 0 11

12 TOTAL THROUGHPUT 4/

3,112 3,016 2,620 2,446 2,180 2,169 2,365 2,375 2,535 2,427 2,611 3,141 2,581 12

REQUIREMENTS FORECAST BY END-USE 5/

13 CORE 6/

Residential 1,036 1,032 805 690 471 384 359 358 364 448 732 1,110 647 1314 Commercial 285 237 235 208 186 207 176 158 167 168 236 267 211 1415 Industrial 58 65 61 59 49 56 51 48 52 54 56 57 55 1516 NGV 41 45 41 42 41 42 41 41 42 41 42 41 42 1617 Subtotal-CORE 1,420 1,379 1,143 999 748 689 627 605 626 711 1,066 1,475 955 17

22 NONCORE Subtotal-NONCORE 1,151 1,112 1,031 1,026 1,055 1,076 1,336 1,366 1,486 1,292 1,090 1,110 1,178 22

26 WHOLESALE & Subtotal-WHOLESALE & INT 501 486 414 391 350 377 373 373 391 394 422 517 415 26INTERNATIONAL

27 Co. Use & LUAF 39 38 33 30 27 27 29 30 32 30 33 39 32 27

28 SYSTEM TOTAL THROUGHPUT 4/

3,112 3,016 2,620 2,446 2,180 2,169 2,365 2,375 2,535 2,427 2,611 3,141 2,581 28

TRANSPORTATION AND EXCHANGE29 CORE All End Uses 73 68 62 57 50 52 47 44 46 47 62 71 57 2930 NONCORE All End Uses 1,151 1,112 1,031 1,026 1,055 1,076 1,336 1,366 1,486 1,292 1,090 1,110 1,178 3033 Subtotal-RETAIL 1,224 1,180 1,094 1,083 1,105 1,129 1,383 1,410 1,532 1,339 1,152 1,181 1,235 33

WHOLESALE &34 INTERNATIONAL All End Uses 501 486 414 391 350 377 373 373 391 394 422 517 415 34

35 TOTAL TRANSPORTATION & EXCHANGE 1,725 1,666 1,507 1,474 1,455 1,506 1,756 1,783 1,923 1,734 1,574 1,698 1,650 35

CURTAILMENT (RETAIL & WHOLESALE)36 Core 0 0 0 0 0 0 0 0 0 0 0 0 0 3637 Noncore 0 0 0 0 0 0 0 0 0 0 0 0 0 3738 TOTAL - Curtailment 0 0 0 0 0 0 0 0 0 0 0 0 0 38

NOTES: 1/ Wheeler Ridge Zone: KR & MP at Wheeler Ridge, PG&E at Kern Stn., OEHI at Gosford) 2/ Southern Zone (EPN at Ehrenberg, TGN at Otay Mesa, NBP at Blythe) 3/ Northern Zone (TW at No. Needles, EPN at Topok, QST at No. Needles, KR at Kramer Jct.)

4/ Excludes own-source gas supply of 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 gas procurement by the City of Long Beach 5/ Requirement forecast by end-use includes sales, transportation, and exchange volumes. 6/ Core end-use demand exclusive of core aggregation transportation (CAT) in MDth/d: 1,395 1,358 1,118 975 722 659 601 581 600 687 1,040 1,454 930

SOUTHERN CALIFORNIA GAS COMPANY 2016 California Gas Report Workpapers-REDACTED 13

13Page 2

Work Paper: TABLE 1-SCG SOUTHERN CALIFORNIA GAS COMPANY



LINE Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Avg LINECAPACITY AVAILABLE

1 California Line 85 Zone (California Producers) 160 160 160 160 160 160 160 160 160 160 160 160 160 12 California Coastal Zone (California Producers) 150 150 150 150 150 150 150 150 150 150 150 150 150 2

Out-of-State Gas

3 Wheeler Ridge Zone (KR, MP, PG&E, OEHI) 1/

765 765 765 765 765 765 765 765 765 765 765 765 765 3

4 Southern Zone (EPN,TGN,NBP) 2/

1,210 1,210 1,210 1,210 1,210 1,210 1,210 1,210 1,210 1,210 1,210 1,210 1,210 4

5 Northern Zone (TW,EPN,QST, KR) 3/

1,590 1,590 1,590 1,590 1,590 1,590 1,590 1,590 1,590 1,590 1,590 1,590 1,590 56 Total Out-of-State Gas 3,565 3,565 3,565 3,565 3,565 3,565 3,565 3,565 3,565 3,565 3,565 3,565 3,565 6

7 TOTAL CAPACITY AVAILABLE 3,875 3,875 3,875 3,875 3,875 3,875 3,875 3,875 3,875 3,875 3,875 3,875 3,875 7

GAS SUPPLY TAKEN8 California Source Gas 122 122 122 122 122 122 122 122 122 122 122 122 122 89 Out-of-State 2,950 2,826 2,502 2,321 2,053 2,022 2,210 2,226 2,377 2,282 2,466 3,002 2,436 910 TOTAL SUPPLY TAKEN 3,072 2,948 2,624 2,443 2,175 2,144 2,332 2,348 2,499 2,404 2,588 3,124 2,558 10


12 TOTAL THROUGHPUT 4/

3,072 2,948 2,624 2,443 2,175 2,144 2,332 2,348 2,499 2,404 2,588 3,124 2,558 12


13 CORE 6/

Residential 1,030 990 800 686 468 382 356 356 362 445 728 1,103 641 1314 Commercial 281 226 231 205 184 204 174 156 165 166 233 263 207 1415 Industrial 57 62 61 58 49 55 51 48 51 54 55 57 55 1516 NGV 43 46 43 44 43 44 43 43 44 43 44 43 43 1617 Subtotal-CORE 1,411 1,323 1,135 993 743 685 624 602 622 707 1,059 1,466 947 17

22 NONCORE Subtotal-NONCORE 1,122 1,113 1,039 1,029 1,059 1,054 1,306 1,344 1,456 1,273 1,077 1,106 1,165 22

26 WHOLESALE & Subtotal-WHOLESALE & INT 502 474 416 390 347 378 373 373 390 393 420 514 414 26INTERNATIONAL

27 Co. Use & LUAF 38 37 33 30 27 27 29 29 31 30 32 39 32 27

28 SYSTEM TOTAL THROUGHPUT 4/

3,072 2,948 2,624 2,443 2,175 2,144 2,332 2,348 2,499 2,404 2,588 3,124 2,558 28

TRANSPORTATION AND EXCHANGE29 CORE All End Uses 73 65 62 57 50 52 47 44 46 47 62 71 56 2930 NONCORE All End Uses 1,122 1,113 1,039 1,029 1,059 1,054 1,306 1,344 1,456 1,273 1,077 1,106 1,165 3033 Subtotal-RETAIL 1,194 1,178 1,101 1,086 1,108 1,107 1,353 1,388 1,502 1,320 1,139 1,177 1,222 33

WHOLESALE &34 INTERNATIONAL All End Uses 502 474 416 390 347 378 373 373 390 393 420 514 414 34

35 TOTAL TRANSPORTATION & EXCHANGE 1,696 1,652 1,518 1,477 1,455 1,485 1,726 1,761 1,892 1,714 1,559 1,690 1,636 35

CURTAILMENT (RETAIL & WHOLESALE)36 Core 0 0 0 0 0 0 0 0 0 0 0 0 0 3637 Noncore 0 0 0 0 0 0 0 0 0 0 0 0 0 3738 TOTAL - Curtailment 0 0 0 0 0 0 0 0 0 0 0 0 0 38

NOTES: 1/ Wheeler Ridge Zone: KR & MP at Wheeler Ridge, PG&E at Kern Stn., OEHI at Gosford) 2/ Southern Zone (EPN at Ehrenberg, TGN at Otay Mesa, NBP at Blythe) 3/ Northern Zone (TW at No. Needles, EPN at Topok, QST at No. Needles, KR at Kramer Jct.)

4/ Excludes own-source gas supply of 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 gas procurement by the City of Long Beach 5/ Requirement forecast by end-use includes sales, transportation, and exchange volumes. 6/ Core end-use demand exclusive of core aggregation transportation (CAT) in MDth/d: 1,385 1,303 1,111 969 718 655 597 578 596 683 1,033 1,444 922

SOUTHERN CALIFORNIA GAS COMPANY 2016 California Gas Report Workpapers-REDACTED 14

14Page 3

Attachment J: 2016 California Gas Report—SDG&E Workpapers

excerpt

2016 California Gas Report Workpapers

REDACTED – For External Distribution

Prepared by

Page 1

Work Paper: TABLE 1-SDGE SAN DIEGO GAS & ELECTRIC COMPANY



LINE Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Avg LINE

CAPACITY AVAILABLE 1/ & 2/

1 California Source Gas 0 0 0 0 0 0 0 0 0 0 0 0 0 1

2 Southern Zone of SoCalGas 1/

607 607 607 607 607 607 607 607 607 607 607 607 607 23 TOTAL CAPACITY AVAILABLE 607 607 607 607 607 607 607 607 607 607 607 607 607 3

GAS SUPPLY TAKEN4 California Source Gas 0 0 0 0 0 0 0 0 0 0 0 0 0 45 Southern Zone of SoCalGas 373 359 303 293 267 297 295 294 311 311 321 387 317 56 TOTAL SUPPLY TAKEN 373 359 303 293 267 297 295 294 311 311 321 387 317 6


8 TOTAL THROUGHPUT 373 359 303 293 267 297 295 294 311 311 321 387 317 8


9 CORE 4/

Residential 135 136 111 95 66 53 49 49 49 58 94 142 86 910 Commercial 54 56 45 45 44 40 36 33 34 36 50 60 44 1011 Industrial 5 6 5 5 4 4 3 3 3 4 4 5 4 1112 NGV 5 6 5 6 5 6 5 5 6 5 6 5 6 1213 Subtotal-CORE 200 204 167 150 119 103 94 91 93 103 154 212 140 13

14 1415 1516 1617 NONCORE Subtotal-NONCORE 170 152 134 139 146 192 198 201 215 205 164 171 174 17

18 Co. Use & LUAF 3 3 3 3 2 3 3 3 3 3 3 4 3 18

19 SYSTEM TOTAL THROUGHPUT 373 359 303 293 267 297 295 294 311 311 321 387 317 19

TRANSPORTATION AND EXCHANGE20 CORE All End Uses 17 18 15 15 14 13 12 11 12 12 15 18 14 2021 2122 NONCORE All End Uses 170 152 134 139 146 192 198 201 215 205 164 171 174 2223 TOTAL TRANSPORTATION & EXCHANGE 187 169 148 154 160 204 210 212 227 217 180 189 188 23

CURTAILMENT24 Core 0 0 0 0 0 0 0 0 0 0 0 0 0 2425 Noncore 0 0 0 0 0 0 0 0 0 0 0 0 0 2526 TOTAL - Curtailment 0 0 0 0 0 0 0 0 0 0 0 0 0 26

NOTES: 1/ Capacity to receive gas from the Southern Zone of SoCalGas is an annual value based on weighting winter and non-winter season values: 607 = (630 winter) x (151/365) + (590 non-winter) x (214/365). 2/ For 2016 and after, assume capacity at same levels. 3/ Requirement forecast by end-use includes sales, transportation, and exchange volumes. 4/ Core end-use demand exclusive of core aggregation transportation (CAT) in MDth/d: 190 194 158 141 110 93 85 83 84 95 144 202 131

San Diego Gas and Electric 2016 California Gas Report-Confidential Workpapers 14

14Page 2

Work Paper: TABLE 1-SDGE SAN DIEGO GAS & ELECTRIC COMPANY



LINE Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Avg LINE

CAPACITY AVAILABLE 1/ & 2/

1 California Source Gas 0 0 0 0 0 0 0 0 0 0 0 0 0 1

2 Southern Zone of SoCalGas 1/

607 607 607 607 607 607 607 607 607 607 607 607 607 23 TOTAL CAPACITY AVAILABLE 607 607 607 607 607 607 607 607 607 607 607 607 607 3

GAS SUPPLY TAKEN4 California Source Gas 0 0 0 0 0 0 0 0 0 0 0 0 0 45 Southern Zone of SoCalGas 372 349 305 291 263 297 295 294 310 309 318 383 315 56 TOTAL SUPPLY TAKEN 372 349 305 291 263 297 295 294 310 309 318 383 315 6


8 TOTAL THROUGHPUT 372 349 305 291 263 297 295 294 310 309 318 383 315 8


9 CORE 4/

Residential 136 132 112 95 67 53 49 49 49 59 94 142 86 910 Commercial 54 54 45 45 43 39 35 33 34 35 49 59 44 1011 Industrial 5 5 5 4 4 4 3 3 3 4 4 5 4 1112 NGV 6 6 6 6 6 6 6 6 6 6 6 6 6 1213 Subtotal-CORE 200 198 167 150 119 103 94 91 93 103 154 212 140 13

14 1415 1516 1617 NONCORE Subtotal-NONCORE 169 148 135 138 142 192 198 200 214 203 161 167 172 17

18 Co. Use & LUAF 3 3 3 3 2 3 3 3 3 3 3 4 3 18

19 SYSTEM TOTAL THROUGHPUT 372 349 305 291 263 297 295 294 310 309 318 383 315 19

TRANSPORTATION AND EXCHANGE20 CORE All End Uses 17 17 15 15 14 13 12 12 12 12 16 18 14 2021 2122 NONCORE All End Uses 169 148 135 138 142 192 198 200 214 203 161 167 172 2223 TOTAL TRANSPORTATION & EXCHANGE 186 165 150 152 155 205 210 211 226 215 177 185 187 23

CURTAILMENT24 Core 0 0 0 0 0 0 0 0 0 0 0 0 0 2425 Noncore 0 0 0 0 0 0 0 0 0 0 0 0 0 2526 TOTAL - Curtailment 0 0 0 0 0 0 0 0 0 0 0 0 0 26

NOTES: 1/ Capacity to receive gas from the Southern Zone of SoCalGas is an annual value based on weighting winter and non-winter season values: 607 = (630 winter) x (151/365) + (590 non-winter) x (214/365). 2/ For 2016 and after, assume capacity at same levels. 3/ Requirement forecast by end-use includes sales, transportation, and exchange volumes. 4/ Core end-use demand exclusive of core aggregation transportation (CAT) in MDth/d: 191 187 158 141 110 93 85 83 84 95 144 202 131

San Diego Gas and Electric 2016 California Gas Report-Confidential Workpapers 15

15Page 3

Attachment K: SoCalGas Advanced Meter Semiannual Report,

February 2018

SOUTHERN CALIFORNIA GAS COMPANY ADVANCED METER

SEMIANNUAL REPORT

February 28, 2018

Page 1

Table of Contents Introduction .................................................................................................................................................. 3

Since the last Conservation Campaign was completed in 2016‐2017 and installation of SoCalGas’

Advanced Meter project is substantially complete, the attached Report represents the last to be

submitted to the Commission pursuant to D.10‐04‐027. ............................................................................. 3

Chapter 1 ‐ Project Overview and Summary ................................................................................................ 3

Chapter 2 ‐ Module Installation and Network Construction Status ............................................................. 5

2.A Module Installation Status ................................................................................................................. 5

2.B Communication Network Construction Status ................................................................................. 6

Chapter 3 ‐ System Performance .................................................................................................................. 8

3.A Network Performance ....................................................................................................................... 9

3.B Billing Data Performance ................................................................................................................ 10

3.C Service Delivery Enhancements resulting from Enhanced Data Analytics ...................................... 11

3.D Extending the Use of the Advanced Meter Network ...................................................................... 12

Chapter 4 ‐ Financial Status ........................................................................................................................ 13

Chapter 5 ‐ Meter Reading Work Force Impacts ........................................................................................ 14

Chapter 6 – Community Education and Outreach ...................................................................................... 16

Chapter 7 ‐ Customer Awareness and Satisfaction ..................................................................................... 16

Chapter 8 – Elevated Customer Inquiries and Deferral/Opt‐Out Program Enrollments ............................ 17

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Southern California Gas Company Advanced Meter Semiannual Report

Introduction

This is the tenth Semiannual Report (“Report”) regarding the progress of Southern California Gas Company’s (“SoCalGas”) Advanced Meter project. In Decision (“D.”) 10‐04‐027, the California Public Utilities Commission (“CPUC” or “Commission”) authorized the project. Ordering Paragraph 5 required the following reporting requirements for SoCalGas:

“Southern California Gas Company shall establish a system to track and attribute program costs and projected savings from conservation. Based on this tracking system, Southern California Gas Company shall submit a report to the Director of the Commission’s Energy Division semiannually, tracking the gas conservation impacts of the advanced metering infrastructure project to date. These reports shall serve as a forum to adjust, as necessary the elements laid out in the final outreach plan described above. We expect that customer outreach, education and communications will continue to evolve and improve as SoCalGas conducts customer research, monitors customer reaction to new AMI technology and various customer usage presentation tools, and incorporates feedback from these activities into its AMI outreach and education activities. If the report shows that the company is falling short of its projections, it shall submit revisions to its conservation plan to increase awareness, participation, and durability of conservation actions among its customers. The semiannual reports and any revisions to the advanced metering infrastructure outreach and conservation plan shall be submitted to the director of the Commission’s Energy Division and served on the most recent service list for this proceeding. Additional costs incurred in order to improve conservation response will be funded out of contingency funds, or otherwise subject to the risk sharing mechanism authorized in Ordering Paragraph 2.”

Since the last Conservation Campaign was completed in 2016‐2017 and installation of SoCalGas’

Advanced Meter project is nearly complete, the attached Report represents the last to be

submitted to the Commission pursuant to D.10‐04‐027.

Chapter 1 ‐ Project Overview and Summary

In addition to the specific requirements identified in D.10‐04‐027, this Report provides overall status of SoCalGas’ Advanced Meter project through December 31, 2017 and builds upon previous Reports by highlighting project changes and activities that have taken place since June 30, 2017. Previous Report filings may be accessed on SoCalGas’ website.1

1 http://www.socalgas.com/regulatory/A0809023.shtml.

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The Advanced Meter infrastructure consists of two primary components – a meter transmission unit (“MTU” or “module”) attached to SoCalGas meters, and a communications network consisting of data collection units (“DCU”) installed across the SoCalGas service territory. Data from the modules is communicated to the DCUs and then transmitted to SoCalGas’ back‐office systems. Operational highlights as of December 31, 2017 include:

Over 5.9 million meter modules installed representing 99% of the total meters to be upgraded.

4,326 data collector units (DCUs) installed and functioning On‐Air representing 95 percent of the estimated 4,535 DCUs planned.

Over 99 percent of the installed modules have been deemed ‘Billing Ready’ and are now used or ready for billing customers.

SoCalGas completed four targeted “Test and Learn” heating season conservation campaigns leveraging Advanced Meter‐enabled usage dataover the course of the project. The goals of these consecutive conservation campaigns were to demonstrate how to best meet the one percent energy savings goal2 associated with the Advanced Meter rollout and to track the resulting conservation savings. In accordance with Ordering Paragraph 5, each of SoCalGas’ successive heating season conservation campaigns incorporated the lessons learned and key findings from the prior campaigns. With each successive campaign, residential conservation treatments produced statistically significant gas savings.3 Of note for the final campaign was that one treatment – a “Seasonal Energy Update” energy report based on advanced meter analytics developed by SoCalGas – achieved the highest savings rate for all four years’ campaigns of 3.43 percent4. Continued savings effects were also realized for treatments initially tested during earlier campaigns. The persistence and sustainability of these conservation results demonstrates the durability of conservation actions as outlined in Ordering Paragraph 5 above. The Advanced Meter project has to date met its schedule, budget and major project milestones; however, continued permitting and construction challenges have impeded completion of the network in accordance with D.10‐04‐027. As discussed in prior Reports, SoCalGas has implemented a proactive public outreach strategy to educate and inform impacted residents, businesses, and municipalities of network installation to help mitigate potential concerns. Despite extensive engagement, select municipalities continue to require SoCalGas to secure discretionary permits. Because discretionary permitting processes are

2 This energy savings goal specifically refers to one percent of total residential gas usage. 3 Four out of eleven treatments tested during the 2013‐2014 heating season campaign generated average savings of about 1.3 percent. Four out of seven residential treatments tested during the 2014‐2015 heating season campaign generated average savings of about one percent. Fourteen out of fourteen residential treatments tested during the 2015‐2016 campaign generated average savings of over 1.4 percent. Eleven out of eleven residential treatments tested during the 2016‐2017 campaign generated average savings of over 1.7 percent. 4 Comprehensive results available in August 2017 Advanced Meter Semiannual Report

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contrary to SoCalGas’ understanding of the CPUCs overarching authority over utility facilities, and because acquiescing to discretionary permitting processes could result in DCUs being rejected or removed by the jurisdiction at any time, SoCalGas has refrained from completing applications in these jurisdictions. Although there has been progress in select areas, by continuing to assert their position these municipalities are considerably delaying or preventing the network installation timeline for over 90 DCUs or two percent of the 4,535 planned DCUs. The inability to deploy the necessary infrastructure in these jurisdictions will continue to result in SoCalGas having to maintain separate meter reading, communications, data processing and billing systems functions for longer than was anticipated in D.10‐04‐027 and may negatively impact expected customer operational and conservation benefits pursuant to Sections 3.C and 3.D of this report. As previously communicated to the Commission, SoCalGas discovered a small percentage of Advanced Meter modules producing inaccurate digital reads of gas usage. The problem was limited to approximately 0.15 percent of the installed population of MTUs. These devices are issuing multiple false alarms. SoCalGas has implemented a plan to replace all defective MTUs, address any authorized billing corrections, and communicate with regulators, customers and stakeholders. During the course of remediation a subsequent issue was identified with MTUs in curb meter vaults. SoCalGas is working with the manufacturer to resolve the issue; until then, these meters will be manually read to minimize any billing impacts to customers. The total financial impact of the issue is unknown at this time, but SoCalGas is seeking parts and labor cost recovery from the vendor. In order to continue to address these remaining implementation aspects of the Advanced Meter project, SoCalGas filed Advice Letters (AL) 5134 and 5215 in 2017. AL 5134 extended the Advanced Meter Infrastructure Balancing Accout (AMIBA) mechanism for at least one year beyond the seven‐year deployment period (2010‐2017) through 2018, or until the associated costs and benefits are incorporated in a subsequent General Rate Case (GRC) and established separate subaccounts in the AMIBA to record costs associated with the deployment and post‐deployment periods of the AMI project as well as for on‐going meter costs in areas where the AMI network is not constructed. AL 5215 revised the AMIBA to reflect that the Deployment Phase Cost Subaccount of the AMIBA will also record costs associated with the installation of Advanced Meter Infrastructure (AMI) communication modules for large commercial and industrial customers and distribution network pressure monitors. These amendments to the AMIBA will ensure that any remainining Advanced Meter project costs are treated in accordance with D.10‐04‐027.

Chapter 2 ‐ Module Installation and Network Construction Status

2.A Module Installation Status

SoCalGas has installed 5,926,881 modules through the end of December 2017, with its first installation dating back to October 2012. Table 1 displays the installations performed by

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Advanced Meter Mass Install personnel and identifies installations completed by other SoCalGas personnel.

Table 1 Module Installations by Personnel Group

Total

Advanced Meter Installations 5,458,310

Other SoCalGas Personnel 468,571

Total Installations 5,926,881

About 92 percent of the modules are being installed by Advanced Meter personnel, with approximately eight percent being installed by other SoCalGas personnel. Other SoCalGas personnel are involved when the installation requires extensive modifications to the existing meter configuration, such as installing the modules on complex industrial and commercial meters; replacing existing curb meters with new curb meters containing a pre‐installed module; and when meters are changed through the normal course of business. Installation teams generally performed work out of warehouses leased specifically for the Advanced Meter project. As part of the planned project shut down, operations at remaining warehouses have completed as of June 30, 2017.

2.B Communication Network Construction Status

The communications network of the Advanced Meter system is designed to ensure that SoCalGas customers receive their hourly consumption data. It consists of DCUs deployed across the SoCalGas service territory that receive the meter reading data from the modules installed on each meter. SoCalGas continues to refine the network to improve system performance and based on the latest propagation study provided by Aclara, the technology vendor, the project plans to install 4,535 DCUs. Table 3 displays the status of the SoCalGas network as of December 31, 2017.

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Table 3 Status of DCUs through December 31, 2017

DCU Status Number of DCUs Percent of DCUs

Installed 4,326 95.4%

On – Air 4,326 95.4%

Negotiating with Local Governments/Other Third Parties5

103 2.3%

Not Started 106 2.3%

Total Planned Installations 4,535 100%

Ninety‐five percent of the network has been constructed or is ready to construct. By December 31, 2017, 4,326 DCUs have been installed and commissioned on‐air and are receiving reads from installed MTUs. SoCalGas continues to negotiate with local governments and third parties to install the remaining DCUs in the network. Table 4 displays the locations of installed DCUs to date.

Table 4

Location of Installed DCUs

DCU Location Installed DCUs

SoCalGas Owned Poles in

SoCalGas Facilities 65

Public Right of Way 2,636

Caltrans Right of Way 83

Private Easement 38

Total 2,822

Attached to Third Party Assets

Los Angeles Bureau of Street Lighting 655

SCE Street Lights 378

PG&E Street Lights 28

SDG&E Street Lights 43

Other Cities Street Lights 315

Other Public/Private Assets 85

Total 1,504

Total DCUs Installed 4,326

5 Includes municipalities refuting the CPUC’s preemptory jurisdiction over utility facilities.

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To date SoCalGas has installed DCUs on a SoCalGas owned pole in the public right of way under its franchise 65 percent of the time. The second most common method has been to install DCUs on local government‐owned street lights. When a DCU is attached to a third party owned asset, SoCalGas negotiates a contract with the asset owner which usually includes:

Fees to lease the space on the asset; and,

Energy rates for the electricity to power the DCU. Of the 12 counties and 211 cities in the SoCalGas service territory, SoCalGas has finished installing DCUs in seven counties and in 178 cities/communities.6 SoCalGas is in active negotiations with several cities and counties to continue installing the remaining DCUs. A limited number of cities and counties have been reopened due to network optimization. To ensure area coverage, the project has reassessed cities and counties that have been completed with the original design and added DCUs where necessary. With 4,326 DCUs constructed, SoCalGas has received 194 complaints and 94 inquiries, including concerns about the DCUs aesthetics, glare, or location. In each case, SoCalGas contacted the complaining party to resolve the complaint. As a result of customer concerns, SoCalGas has relocated 89 DCUs. Otherwise, the concerns have been resolved without relocating the DCU. Where the DCU design point falls entirely within private property, SoCalGas negotiates easements with the private property owner(s). Installations of this type usually require a contract to secure the right to locate on the third party property. When SoCalGas installs a DCU on its own pole, the DCU is solar‐powered. When installed on a street light, the DCU is most often powered by electricity from the street light. Given the preponderance of new poles, most of the DCUs are solar powered. Table 5 shows the breakdown between solar and A/C powered DCUs.

Table 5

Power Source for DCUs

Installed DCUs Solar Powered AC Powered

4,326 2,921 1,405

Chapter 3 ‐ System Performance

Two key indicators of the overall Advanced Meter system performance are the performance of the network with respect to the delivery of hourly data for billing and online presentation purposes, and the resulting billing data‐related performance. Additional improvements to SoCalGas’ service delivery are also being realized as a result of meter read automation and

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enhanced data analytics capabilities enabled by the Advanced Meter system. Extended uses of the Advanced Meter system through a network sharing capability also have the potential to provide additional operational and conservation benefits to water agencies and their customers within SoCalGas’ service territory.

3.A Network Performance

The most basic measure of system performance is to measure the data delivered as a percentage of the expected data to be delivered. This has direct impacts to both billing and the presentment of hourly gas consumption data to customers. In a perfect system, SoCalGas would receive data for every customer for every hour, each day of the year. To provide this data, the modules must communicate with the DCUs and the DCUs must transmit the data to SoCalGas back office systems 100 percent of the time. Table 6 displays the breakdown of modules that have successfully communicated with SoCalGas’ back office systems.

Table 6 Module Communication Status

Module Communication Status Modules Installed Percent Installed With Network

Total Modules Installed 5,926,881 ‐

Modules installed but not yet communicating with HE systems7

16,539 ‐

Delivering 100 Percent of Expected Reads 5,619,087 95.1%

Missing 1‐12 Reads 188,722 3.2%

Missing More Than 12 Reads 95,151 1.6%

Missing All Reads 7,382 0.1%

SoCalGas generally installs modules where the network is available; however, some exceptions to installing outside of an available network include instances when new business meters are connected and routine meter changes are being performed. Additionally, when a meter fails in the field, it is replaced with an integrated meter and module, regardless of whether the network is installed or not. As illustrated in Table 6, approximately 95 percent of the installed modules are successfully communicating all of a customer’s hourly data on a monthly basis. About three percent of the modules are missing 1‐12 reads, which means that they have had only one or two unsuccessful communications per month. That is, one or two six‐hour periods have not been successfully communicated to the SoCalGas back office systems. SoCalGas does not consider a module performing at this level to be problematic for billing as enough hourly data is being received for these purposes.

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About two percent of the modules are missing more than 12 reads but have communicated at least one read. SoCalGas continues to examine module modifications and network enhancements to improve the performance of these modules.

3.B Billing Data Performance

The Advanced Meter modules replace the manual reads with an automated read, with the expectation that the system will produce more accurate reads (no data entry mistakes) and fewer estimated reads (meter access problems are largely eliminated). Table 7 displays the progression of modules from installation to actual use for billing.

Table 7

Advanced Meters Utilized for Billing

Modules Installed as of December 31, 2017 5,926,881

Modules in ‘Billing Ready’ Status 5,894,443

Billing Data Provided by Advanced Meter 5,885,012

Billing Data Not Provided by Advanced Meter 5,894

Percent Provided by Advanced Meter – Actual Read 99.84%

Percent Provided by Advanced Meter – Estimated Read 0.06%

Percent Not Provided by Advanced Meter 0.1%

Approximately 99 percent of the installed modules have been deemed ‘Billing Ready’ and are now used or ready for billing customers. Of the remaining one percent, most are still in the process of completing one of the test elements needed to become ‘Billing Ready.’ Others are located in areas with incomplete DCU coverage, or are located in areas with insufficient module density to support conversion to Advanced Meter billing. Modules in areas with network coverage which do not pass the ‘Billing Ready’ tests are monitored and, if necessary, replaced. They may also point to insufficient network coverage or DCU problems, which are then remediated.8 For the Billing Ready modules, the system provides a high percentage of actual reads. The system also provided 0.06 percent of reads which were ‘estimated reads’ based substantially on reads received earlier in the month, rather than on a particular designated day. Only about 0.1 percent of the reads could not be provided by the Advanced Meter system. In July 2013, SoCalGas implemented software that enabled the utilization of automated reads for the initiation of new service and generation of closing bills. With Advanced Meter automation, a field visit to collect a customer’s starting read was no longer necessary for turn‐on orders that did not require entry into the home. SoCalGas’ Customer Service Field

8 As referenced in Chapter 2, additional DCUs may have to be added to improve system performance.

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organization has seen a reduction of over 3.3 million orders since the implementation of the automated reads.

3.C Service Delivery Enhancements resulting from Enhanced Data Analytics

As the Commission articulated in the AMI decision,9 the Advanced Meter system “provides [a] system‐wide technology platform with the ability to expand operating benefits as new applications emerge.” In areas where the communications network is fully deployed, SoCalGas is leveraging Advanced Meter‐enabled data analytics and technology by integrating data to develop algorithms that support the continued safe and reliable delivery of natural gas to its customers. These enhanced data analytics enable identification of unusual gas consumption patterns at customer facilities. Though in the exploratory phase, this new and more granular awareness of energy data utilization is uncovering new opportunities and benefits potential. Leveraging the Advanced Meter network could result in faster identification of abnormally high gas usage, which enables SoCalGas to identify, investigate, and respond to potential safety situations quicker. By discovering abnormally high gas usage and notifying customers, SoCalGas can reduce methane emissions at customer facilities saving energy and improving air quality while also reducing the financial burden on customers from higher usage. The Advanced Meter team assesses unusual consumption patterns on closed accounts using a Per Day Average and in some cases will look at the hourly reads to conduct further research. During the exploratory phase of SoCalGas’ enhanced data analytics, the following results have been achieved. Table 8 summarizes the results of the 8,335 exploratory service orders fielded through December 31, 2017.

9 D. 10‐04‐027, page 40.

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Table 8 Gas consumption data analytics results through December 31, 2017

Findings from completed field visits (project to date) Number of field visits

Percent

Total field visits generated by consumption analytics awareness 8,335

Gas services closed by SoCalGas field technician due to excessive registration, awaiting resolution. Resolution takes place at the time of the follow‐up field visit to reinstate gas service.

3,447 41.36%

Gas leak found by SoCalGas field technician 2,193 26.31%

Gas or hot water leaks corrected by the customer as a result of SoCalGas field visit

1,084 13.01%

Hot water leaks where the hot water heater was in continuous demand

995 11.94%

Abnormal gas usage resulting from an appliance in use for an extended period of time (e.g., appliances unintentionally left on).

616 7.39%

Leveraging Advanced Meter consumption analytics is a component of a more comprehensive set of processes and inspections aimed at ensuring public safety and SoCalGas expects that, as it continues to build out enhanced analytics capabilities enabled by the Advanced Meter system, further customer service and safety benefits will accrue to its customers. More rapid detection and resolution of gas and hot water leaks provides enhanced safety for customers and their communities, as well as provides energy and financial savings, reduced greenhouse gas emissions, and conservation of our scarce water supplies.

3.D Extending the Use of the Advanced Meter Network

As articulated in our AMI Application, SoCalGas recognizes the State’s priority and urgency in encouraging and enabling water conservation and as such included the requirement for an AMI technology capable of reading water meters. This network sharing capability has the potential to provide significant operational and conservation benefits to water agencies and their customers within SoCalGas’ service territory. In order to operationally evaluate the feasibility of the “Shared Network” concept, SoCalGas established pilots to be conducted by Aclara and SoCalGas with a limited number of water utilities. Additionally, as part of the SoCalGas Water Energy Nexus (WEN) AMI Pilots which were approved by the CPUC on June 9, 2016 with D.16‐06‐010, SoCalGas partnered with a 3rd party analytics vendor (Valor Water Analytics) and two separate Commission‐regulated water utilities (San Gabriel Valley Water Company, California American Water).

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In addition to the Advanced Meter network being shared by external water utilities, other groups within SoCalGas are leveraging the network. As part of a pilot project by the Pipeline Safety Enhancement Plan (PSEP) group, data from a sensor device to detect, measure and monitor methane in the area near a transmission pipeline is being transmitted over the Advanced Meter network. These methane sensor devices, installed in 2016, continue to successfully communicate over the Advanced Meter network and provide SoCalGas with remote alarm registration and processing when the methane‐in‐air concentration, as measured by the sensors, exceeds limits established for our testing period.

Chapter 4 ‐ Financial Status

To track expenses during the project, Ordering Paragraph 7 of the D.10‐04‐027, stated:

“Southern California Gas Company shall file an advice letter no later than 30 days from

the effective date of this decision, establishing a balancing account and detailing the cost

recovery mechanism in conformance with this decision. Southern California Gas

Company is authorized to recover deployment costs up to $1.0507 billion in this account,

plus additional amounts, if any, consistent with the terms and conditions of the Risk

Sharing Mechanism approved in Ordering Paragraph 2.”

On August 4, 2010, the CPUC approved AL 4110, effective April 8, 2010, which established the Advanced Meter Infrastructure Balancing Account. The CPUC approved budget of $1,050 million for the SoCalGas Advanced Meter project was augmented by re‐directing $13.5 million of previously approved General Rate Case funding for a Remote Automated Meter Reading (“RAMR”) project. SoCalGas halted the implementation of its RAMR project, a drive‐by meter reading system, when its Advanced Metering Infrastructure (“AMI”) application was submitted, and in the AMI application requested that this funding be re‐directed to the Advanced Meter project. In D.10‐04‐027, the CPUC approved this request.10 Due to the timing of the AMI application and Decision, the project deployment period overlapped with SoCalGas’ TY 2012 and TY 2016 General Rate Case (GRC) schedules. Since AMI deployment costs and benefits are recorded in the AMIBA, AMI impacts could not be integrated into GRC forecasts until TY 2019. As a result, SoCalGas requested authorization in the TY 2016 to establish a 2018 “bridge‐year” period – the year between the end of deployment in 2017 and the TY 2019 GRC. Subsequently, on May 5th, 2017, SoCalGas filed Advice Letter 5134 to request the 2018 bridge‐year period, referred to in the Advice Letter as the “post‐deployment phase cost sub‐account.”11 The total budget for the SoCalGas Advanced Meter project is $1,064 million, which included a contingency fund of $68.7 million.

10 A.08‐09‐023, Prepared Direct Testimony of Edward Fong, page 15. 11 AL 5134 with sub‐account details is available at the following site: https://www.socalgas.com/regulatory/tariffs/tm2/pdf/5134.pdf

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The sequencing of the spending to date is typical of the pattern for many major projects. The early years of the project were spent organizing the large project team; developing new business processes; and building and implementing the information systems that support the construction of the DCUs and installation of the modules. SoCalGas’ plan contemplated that the DCUs would be constructed prior to the installation of the modules so that the modules would be effective in delivering benefits to customers. As indicated in Chapter Two, SoCalGas began installing its DCUs in June 2012 and its modules in October 2012.

Table 9

Financial Results (in $Thousands)

Recorded 2010 through December 2017

2010 2011 2012 2013 2014 2015 2016 2017

Project to Date

Project Management Office 2,719 6,477 6,634 4,945 4,027 3,415 3,006 2,854 34,077

Meters, Modules & Installation 120 3,718 28,410 115,516 183,117 170,078 58,829 7,833 567,620

Network 877 3,743 14,429 23,805 18,796 15,306 14,572 13,461 104,989

Information Technology 6,011 16,873 21,931 16,015 10,469 11,109 6,248 5,775 94,430

Customer Outreach 324 1,026 2,088 5,502 5,190 4,786 3,999 2,143 25,057

Employee Awareness 65 3,078 3,732 2,088 1,046 1,087 752 383 12,231

Support Organizations12 ‐ ‐ 707 3,500 4,517 4,684 11,512 2,145 27,065

Overheads & AFUDC13 2,222 9,471 21,291 32,577 38,311 32,268 29,433 14,257 179,830

Total 12,338 44,386 99,223 203,947 265,472 242,732 128,350 48,851 1,045,300

Table 9 displays the Advanced Meter spending through December 31, 2017, by the major project activities. The purchase and installation of meters and modules continue to be the primary source of spending at approximately $570 million project to date. The next large areas of spend are in the construction of the communication network and information systems with approximately $104 and $94 million in spend, respectively. Although the project has fully allocated the authorized contingency SoCalGas believes the project will be delivered within the approved budget.

Chapter 5 ‐ Meter Reading Work Force Impacts

The Meter Reading work force is the most significantly impacted by the Advanced Meter project as Meter Reading positions will all but be eliminated by the project.14 Both SoCalGas and the CPUC are concerned about these impacts. The Commission specifically addressed this concern. Ordering Paragraph 1 of the D.10‐04‐027 states:

12 Support organizations are comprised of SoCalGas departments outside of Advanced Meter that are funded by the project for project related work or for work identified in business case. This includes field work related to advancing our larger meters (primarily commercial and industrial). 13 Updated to exclude the Pension & Benefits refundable portion that is balanced separately from the AMI project. 14 Some personnel may continue to manually read meters in support of the CPUC authorized Opt‐Out program.

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“Southern California Gas Company shall supplement by $1 million, its funding for workforce retention and retraining. This fund is established to better protect the employment interests of Southern California Gas Company’s meter reading workforce and should be used to extend severance, vocational training, and other transitional opportunities to employees affected by the decision to pursue advanced metering infrastructure.”

In response to this direction, SoCalGas set aside funding in its Enhanced Educational Assistance Fund specifically to support the Meter Reading personnel in place in April 2010. Through the project deployment period, meter readers have been reimbursed over $100,000 through this fund. While meter readers have been active in seeking employment opportunities within SoCalGas the fund had not been heavily utilized, so as part of continuing efforts to support our employees’ transition to potential job opportunities, SoCalGas expanded the retention and retraining efforts to include skills orientation workshops. These workshops were designed to familiarize employees with the mechanical and technical skills associated with piping, tools usage, natural gas appliance and distribution system construction work. The orientation workshops offered transitional skills that could be applied toward job opportunities within and outside of SoCalGas. The target employee group was expanded to include all current meter reading employees as well as AMI Field Representatives. All of these employees will be affected when Advanced Meter implementation is completed in 2017. SoCalGas allocated $42,400 from the authorized funding from 4th Quarter 2014 through 2017 to provide these workshops for employees. Table 10 displays the current status of those Meter Reading personnel who were employed in April 2010, when the project was approved by the CPUC.

Table 10

Status of Meter Reading Personnel Employed in April 2010

Meter Reading Personnel

Work Force in April 2010

Remain in Meter Reading

June 30, 2017 Left Company

Transition Within

Company

Full‐time 166 2 24749

Part‐time 818 17 192

Management 46 7 14 25

Total 1,030 26 230 774

Percent of Work Force

100% 2.52% 22.33% 75.15%

As Table 10 shows, 774 employees (over 75 percent of the Meter Reading personnel from April 2010) have transitioned to another position within SoCalGas. Twenty‐two percent of those

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employed in 2010 have left SoCalGas and 26 employees (less than 3 percent) remain in the Meter Reading organization. SoCalGas continues to encourage Meter Reading employees to explore all company opportunities outside of the Meter Reading organization.

Chapter 6 – Community Education and Outreach

SoCalGas personnel performed an array of outreach activities to inform customers about Advanced Meter project activity. SoCalGas developed a local stakeholder education and community outreach program to ensure every city and county SoCalGas serves is addressed. During the network construction process, outreach is done at the city level with initial city briefings to the city manager and staff including informational presentations to city councils as well as any other sub‐committees as necessary. Outreach to the community includes, but is not limited to: one‐on‐one customer meetings, door knocking, and meetings with homeowner associations, community/neighborhood councils, community groups, and mailings. These efforts include briefing local elected officials, media outreach, community town hall events and local speaking engagements.

Chapter 7 ‐ Customer Awareness and Satisfaction

From 2010 through 2016, SoCalGas monitored the impact of its outreach activities in the areas of customer awareness and customer satisfaction. SoCalGas utilized a variety of market research diagnostics to monitor the “pulse” of customers pertaining to the Advanced Meter installation process, customer communications, new programs and services, and customer attitudes and motivational drivers to behavioral change. For purposes of monitoring overall customer awareness and perceptions, SoCalGas used the Customer Insight Study (“CIS”)15 which is administered by Davis Research. CIS is SoCalGas' public opinion tracking study. Starting in the fourth quarter of 2010, SoCalGas added three Advanced Meter related questions to this tracking survey. The questions were then updated slightly in the fourth quarter of 2012, commensurate with the initial deployment of Advanced Meters. These questions were fielded through the fourth quarter of 2016, and then discontinued going forward given that 96 percent of the installations were completed by the end of 2016. A consistent finding of the quarterly CIS results was that awareness levels amongst residential and business customers increased gradually over the course of the project rollout. The general upward trend seems to reflect the increased volume of customer communications about the project as well as an increase in installations.16

15 Formerly called iTracker Customer Perception Study. 16 Please refer to prior years’ Reports for further details regarding Customer Awareness and Satisfaction research conducted over the course of the Advanced Meter project.

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Chapter 8 – Elevated Customer Inquiries and Deferral/Opt‐Out Program Enrollments

SoCalGas customers may inquire about the Advanced Meter project by contacting either the SoCalGas Customer Contact Center (“CCC”) or the Advanced Meter Customer Information Center (“CIC”). The CCC addresses customer inquiries about any subject while the CIC typically makes appointment arrangements with customers to have their Advanced Meter installed. Advanced Meter “opt‐out” requests are processed by the CCC. Some customer inquiries were not routinely resolved and were escalated to Advanced Meter Customer Experience staff. There have been about 9,000 inquiries since the project’s inception. The number of escalated customer inquiries is very low, considering the volume of Advanced Meter communications that have been distributed to SoCalGas customers. The most common cause of the escalated inquiries is requests to defer/opt‐out of the installation of the Advanced Meter communications module. Although customers can call either the CCC or the CIC to have their deferral/opt‐out requests recorded, some ask to speak to the Advanced Meter Customer Experience staff. Their questions usually revolve around safety and privacy concerns, as well as comments on the Advanced Meter Opt‐Out Program fees. Table 11 displays a breakdown of enrollment status for the Advanced Meter Opt‐Out Program as of December 31, 2017.

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Table 11

Advanced Meter Opt‐Out Program Enrollment

Inquiry Type Number Received

Explanation

Active customer‐requested Opt‐Out Program enrollments17

7,574 The number of customers actively enrolled and being billed for Opt‐Out Program fees and charges.18

Active customers defaulted in to the Opt‐Out Program

17,570 The number of customers that have been default enrolled19 and are being billed for Opt‐Out Program fees and charges.

Total Active Opt‐Out Program enrollments

25,144 (0.42%)

Customer Opt‐Out Program requests to “opt back in” to Advanced Meter installation

56,677 The number of customers that requested to be removed from the Opt‐Out Program (includes customers in both an “Active” and “Pending Enrollment” Opt‐Out Program status).

In March 2014, SoCalGas’ Opt‐Out Program became effective and the project team initiated efforts to inform employees of the Opt‐Out Program and revised any impacted company communication materials. The interim opt‐out fees approved by the Commission were consistent with those previously adopted for the other California Investor‐Owned Utilities (“IOUs”).20 SoCalGas’ Advanced Meter Opt‐Out Program interim fees for residential customers were as follows:

o Non‐CARE Customers: Initial fee of $75.00 and $10.00/month ongoing cost

o CARE Customers: Initial fee of $10.00 and $5.00/month ongoing cost

In December 2014, the Commission issued D.14‐12‐078 regarding the Smart Meter Opt‐Out Phase 2 proceeding; this decision reiterated approval of the interim opt‐out fees and charges and adopted them as permanent opt‐out fees and charges for residential customers for each of the California IOUs.

17 “Active" includes only those customers who are enrolled in the Opt‐Out Program and are currently being billed associated Opt‐Out Program fees. Many customers in a “Pending” status, once presented with final communications regarding Opt‐Out Program fees, elect to terminate their prior request for enrollment in the Opt‐Out Program. Similarly, customers about to be default‐enrolled due to repeated installation/access attempts sometimes contact SoCalGas to schedule an installation prior to being actively enrolled. 18 SoCalGas implemented its Advanced Meter Opt‐Out Program effective March 19, 2014, pursuant to D.14‐02‐019. These customers either requested to defer from an Advanced Meter module installation prior to March 19, 2014, or subsequent to March 19, 2014, requested to enroll in the Advanced Meter Opt‐Out Program. 19 These customers were defaulted (automatically enrolled) into the Opt‐Out Program due to several unsuccessful attempts by SoCalGas to contact the customers to provide access for the installation of the Advanced Meter. 20 D.12‐02‐014 (PG&E), D.12‐04‐018 (SCE), and D.12‐04‐019 (SDG&E).

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In April 2015, pursuant to the Commission’s Phase 1 and Phase 2 Opt‐Out decisions, SoCalGas implemented modifications to its billing system to begin charging opt‐out fees to Opt‐Out Program participants, including customers who were defaulted into the program. Additionally, information regarding key new features introduced in the Phase 2 decision was incorporated into existing customer talking points and all relevant Advanced Meter customer and external communications materials. SoCalGas still expects the total percentage of customers who will eventually opt‐out to be within the planning assumption of 0.5 percent.

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Attachment L: A.17-10-007, Applicants’ Response to SCGC-02

SCGC-SEU DATA REQUEST-002 SDG&E-SOCALGAS 2019 GRC – A.17-11-007/8

SEU RESPONSE DATE RECEIVED: FEBRUARY 20, 2018

DATE RESPONDED: MARCH , 2018

2.1. Witness Rene F. Garcia states in SCG-17-R at RFG-5, lines 10-14:

Prior to the installation of the AMI technology, gas consumption at premises with installed security devices was identified as part of the Billing exception processes by the Customer Information System (CIS). Billing analysts would be required to evaluate and schedule additional visits to the meter if deemed as required. With AMI, SoCalGas can now identify and investigate these possibly unsafe situations more quickly.

2.1.1. Please confirm that the Customer Information System (“CIS”) is used to prepare customer bills.

2.1.2. Please confirm that the CIS contains information about customers that includes service address (location of meter), billing address, whether the customer is core or noncore, rate schedule(s) that apply to customer for billing purposes, and for core customers the identity of the provider of gas procurement services.

2.1.3. Does the CIS include a unique meter number for each customer premises?

2.1.4. Does the CIS include a unique MTU identifier for each customer premises?

2.1.5. Please confirm that when the CIS prepares a bill for a customer, it first uploads hourly meter read data from the Meter Data Management System for the relevant billing period.

2.1.6. Please confirm that data from the CIS is periodically uploaded to the Data Warehouse and state the frequency with which the CIS data is uploaded to the Data Warehouse.

Utility Response 2.1:

SoCalGas objects to this request under Rule 10.1 of the Commission’s Rules of Practice and Procedure to the extent it seeks the production of information that is neither relevant to the subject matter involved in the pending proceeding nor is likely reasonably calculated to lead to the discovery of admissible evidence. Subject to and without waiving the foregoing objection, SoCalGas responds as follows.

Repsonse to 2.1.1. Yes, this is correct.

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Utility Response 2.1 Continued:

Response to 2.1.2. Yes, this is correct.

Response to 2.1.3. Each gas meter has a unique identifier (the Meter Badge number) associated with it and each MTU has a unique identifier (MTU serial number) associated with the MTU. However a customer premise, such as an apartment complex, may have multiple meters associated with it.

Resonse to 2.1.4. See response to 2.1.3.

Response to 2.1.5. The night prior to the billing generation, CIS will request the 3:00 AM read associated with every account from the MDMS that is to be billed within the next day’s bill generation process.

Repsonse to 2.1.6. A daily upload of the prior-day CIS data occurs for master data and transactional data (bills, payments, service orders, etc.) and a monthly upload occurs for revenue data.

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DATE RESPONDED: MARCH , 2018 2.2. Witness Rene F. Garcia states in SCG-17-R at RFG-8, lines 3-9:

An MTU is a communications device that automatically and securely transmits hourly gas meter readings to our DCUs, which in turn transmit the gas meter readings to our back-office systems (e.g. MDMS and HE) and billing department, eliminating the need for manual meter reading. While gas usage is still measured by the analog meter as it was prior to adding the AMI technology, the MTU is applied (retrofitted) to the meter to securely transmit hourly meter readings wirelessly through SoCalGas’ data communications network.

2.2.1. Please confirm that each meter transmission unit (“MTU”) installed on a meter has a unique identifier. 2.2.2. Please confirm that the drive shaft for the analog meter passes through the MTU assembly, which by means of a coupler and magnet on the meter drive shaft is able to count the number of clicks or index counts that the meter has advanced forward each hour relative to a baseline number identified for an anchor hour. 2.2.3. Please confirm that four times each day the MTU transmits to the data collection unit (“DCU”) packets of encrypted data containing the MTU unique identifier, an anchor “read” and eleven hourly index counts. The anchor read and five index counts were previously transmitted to the DCU and six index counts have not previously been transmitted to the DCU. 2.2.4. Does each MTU have the same anchor hours, that is 6:00 a.m., 12:00 p.m., 6:00 p.m., and 12:00 a.m., or do some MTUs have anchor hours that differ from this, for example, 1:00 a.m., 7:00 a.m., 1:00 p.m., and 7:00 p.m., or 2:00 a.m., 8:00 a.m., 2:00 p.m., and 8:00 p.m.? 2.2.5. Please confirm that the MTU randomly schedules the transmit time for the packet of encrypted data during a six-hour interval following the recording of the last index count that is included in the packet. For example, for a 6:00 p.m. data packet that includes a 6:00 a.m. anchor and 11 hourly index counts from 7:00 a.m. through 5:00 p.m., the data packet could be transmitted any time after 6:00 p.m. and before 12:00 a.m.

Utility Response 2.2: SoCalGas objects to this request under Rule 10.1 of the Commission’s Rules of Practice and Procedure to the extent it seeks the production of information that is neither relevant to the subject matter involved in the pending proceeding nor is likely reasonably calculated to lead to the discovery of admissible evidence. Subject to and without waiving the foregoing objection, SoCalGas responds as follows.

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DATE RESPONDED: MARCH , 2018 Utility Response 2.2 Continued: Response to 2.2.1. Yes, each MTU has a unique MTU serial number associated with it. Response to 2.2.2. Yes, this is correct. Response to 2.2.3. Yes, this is correct. Note, the current anchor read was not transmitted in the previous transmission; that hour’s data, in the previous transmission, was hour 6’s incremental index count. Response to 2.2.4. All modules will be on one of six data transmittal schedules:

• S1: 12:00 a.m., 6:00 a.m., 12:00 p.m., 6:00 p.m. • S2: 1:00 a.m., 7:00 a.m., 1:00 p.m., 7:00 p.m. • S3: 2:00 a.m., 8:00 a.m., 2:00 p.m., 8:00 p.m. • S4: 3:00 a.m., 9:00 a.m., 3:00 p.m., 9:00 p.m. • S5: 4:00 a.m., 10:00 a.m., 4:00 p.m., 10:00 p.m. • S6: 5:00 a.m., 11:00 a.m., 5:00 p.m., 11:00 p.m.

All communication modules will be assigned a schedule shortly after the module is provisioned and communicating to the network. Response to 2.2.5. Yes, this is correct.

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2.3. Witness Rene F. Garcia states in Exhibit SCG-17-R at RFG-8, lines 12-19: The AMI communication network will include nearly 4,600 DCUs by TY 2019 across the SoCalGas service territory. The DCUs receive the meter reading data from the MTUs installed on each meter. The data is encrypted and transmitted wirelessly across a licensed frequency from the MTU to the DCU. The specific DCU locations, referred to as design points, take into account the location of the approximately six million meters, the topography of the surrounding area, and the influence of the built environment on the transmission of the radio signal. DCUs can be placed within a 500-foot radius of a design point. Most MTUs will communicate with at least three DCUs. 2.3.1. Please confirm that the DCUs transmit data from the MTUs at least every 15 minutes although some DCUs may transmit data more frequently than every 15 minutes. 2.3.2. Please confirm that the DCUs transmit the encrypted data packets from the MTUs to the Head End (“HE”) system using Verizon and AT&T cellular systems and, in some cases, ethernet connections. 2.3.3. Please confirm that it takes approximately 15 minutes for data from an MTU to be transmitted through the DCUs to the HE.

Utility Response 2.3: SoCalGas objects to this request under Rule 10.1 of the Commission’s Rules of Practice and Procedure to the extent it seeks the production of information that is neither relevant to the subject matter involved in the pending proceeding nor is likely reasonably calculated to lead to the discovery of admissible evidence. Subject to and without waiving the foregoing objection, SoCalGas responds as follows. Response to 2.3.1. Yes, this is correct.



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DATE RESPONDED: MARCH , 2018 2.4. Witness Rene F. Garcia states in Exhibit SCG-17-R at RFG-8 to RFG-9, lines 28-5:

The third component of the infrastructure includes the AMI Information Technology (IT)systems, including the Head End (HE) and the Meter Data Management System (MDMS). Meter reading data from the MTU is communicated to the DCUs and then transmitted to these systems. and also states in Exhibit SCG-17-R at RFG-20, lines 6-8: The HE software collects and processes meter data and pressure alarms and other data needed to help AMI support groups operate and manage the AMI network. 2.4.1. Please confirm that the HE collects the meter data for all nearly 5.9 million meters that have been added to the AMI system from the DCU and decrypts the data, identifies duplicate data collected from more than one DCU, and verifies the validity of the data by identifying any inconsistencies in the duplicate data and confirming the MTU identifier. 2.4.2. Please confirm that the HE also identifies any problems or failures that might occur with the individual DCUs. 2.4.3. Please confirm that the HE converts the hourly index counts transmitted from the MTUs into hourly readings of cubic feet of gas consumed. 2.4.4. Please confirm that it takes approximately 15 minutes to process and validate hourly meter reads received in the HE and transmit it to the MDMS system although data from the HE is held in staging tables until uploaded into the MDMS system. 2.4.5. Please confirm that the processed and validated hourly meter reads received from the HE and held in the staging tables are uploaded to the Meter Data Management System (“MDMS”) four times per day at 05:00 a.m., 11:00 a.m., 3:00 p.m., and 11:00 p.m.

2.4.6. Please confirm that approximately 40 percent of the meters have had 100 percent of their data for the previous metering day uploaded to the MDMS system at 05:00 a.m. 2.4.7. Please confirm that approximately 90 percent of the meters have had 100 percent of their data for the previous metering day uploaded to the MDMS system at 11:00 a.m. 2.4.8. Please confirm that all meters have had 100 percent of their data for the previous metering day uploaded to the MDMS system as of 3:00 p.m.

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Utility Response 2.4: SoCalGas objects to this request under Rule 10.1 of the Commission’s Rules of Practice and Procedure to the extent it seeks the production of information that is neither relevant to the subject matter involved in the pending proceeding nor is likely reasonably calculated to lead to the discovery of admissible evidence. Subject to and without waiving the foregoing objection, SoCalGas responds as follows. Response to 2.4.1. Yes, this is correct. Response to 2.4.2. The Head End (HE) system identifies problems or failures that might occur with the individual DCUs. Response to 2.4.3. For an individual MTU’s transmission, the HE only stores the anchor reads and the 11 incremental changes. The HE does not store MTU reads or hourly usage data (the subtraction of one hour’s meter read from the next). The MDMS stores MTU reads (converted from the 11 incremental deltas) and hourly usage. When the interface process loads HE data into the MDMS, that process transforms the data from incremental deltas (stored in the HE) to MTU reads and hourly usage. Response to 2.4.4. Once data is in the HE, every 15 minutes the data is copied to staging tables. Four times daily (per the schedule outlined in Question 2.4.5), the data in these staging tables are validated and loaded into the MDMS. Response to 2.4.5. Yes, this is correct. Response to 2.4.6. Yes, this is correct for those MTU’s that have successfully transmitted their data. Response to 2.4.7. Yes, this is correct for those MTU’s that have successfully transmitted their data. Response to 2.4.8. Yes, this is correct for those MTU’s that have successfully transmitted their data.

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2.5. Witness Rene F. Garcia states in Exhibit SCG-17-R at RFG-20, lines 8-9:

The MDMS software is the system of record for AMI meter reads, gas usage, and MTU tamper alerts. 2.5.1. Please confirm that the MDMS system holds the hourly meter reads in terms of cubic feet of gas usage for all meters that are included in the AMI system, currently estimated as nearly 5.9 million meters. 2.5.2. Please confirm that the MDMS provides the hourly meter gas usage reads to the CIS system when this data is requested for use in preparing customer bills. 2.5.3. Please confirm that the MDMS provides the hourly meter gas usage reads to other systems, for example, MDMS provides data to MyAccount when this data is requested by customers online. 2.5.4. Please confirm that once a day at 5:00 p.m. the MDMS system uploads to the Data Warehouse a complete set of hourly meter reads for the previous Gas Measurement Day for all of the nearly 5.9 million meters that are included in the AMI system.

Utility Response 2.5: SoCalGas objects to this request under Rule 10.1 of the Commission’s Rules of Practice and Procedure to the extent it seeks the production of information that is neither relevant to the subject matter involved in the pending proceeding nor is likely reasonably calculated to lead to the discovery of admissible evidence. Subject to and without waiving the foregoing objection, SoCalGas responds as follows. Repsonse to 2.5.1. Yes, the MDMS is the system of record for MTU reads and hourly usage data. Repsonse to 2.5.2. Yes, when requested, the MDMS will provide the 3:00 AM meter read (or MTU read) for those meters being billed. Even though the MDMS stores hourly usage, it is CIS that performs the consumption calculation for billing purposes. Repsonse to 2.5.3. Yes, when requested, the MDMS will provide the requested customer’s usage to MyAccount.

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Repsonse to 2.5.4. Daily, the Data Warehouse initiates several load processes that transfers hourly reads and usage data (in cubic feet, not therms) to the Data Warehouse. This process is complete by 5:00 PM.

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DATE RESPONDED: MARCH 6, 2018

2.6. Regarding the response to SCGC-01, Q.1.4.1, which states “Existing data set holds advanced meter interval data only for meters with AMI modules installed. Data is not available for customers who have opted out of AMI or for customer meters that have yet to be converted to AMI.”

2.6.1. Does the existing data set holding the “big data volumes generated from Advanced Meter (AM) interval data” referred to in Witness Christopher Olmsted states in Workpaper SCG-26-CWP at page 193 of 871 contain data from all core customer meters that are currently included in the AMI system?

2.6.2. Given the statement of witness Rene F. Garcia in Exhibit SCG-17-R at RFG-20, lines 8-9: “As of June, 2017, nearly 5.9 million meters have been retrofitted with an MTU,” would the existing data set hold AMI data for nearly 5.9 million customer meters?


Response to Q.2.6.1: Yes

Response to Q.2.6.2: Yes

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DATE RESPONDED: MARCH 6, 2018 2.7. Regarding the response to SCGC-01, Q.1.4.3, which states “the AM database is uploaded

once per day at 5:00 PM with data from the previous calendar day.” 2.7.1. Is the AM database uploaded to the “Data Warehouse” once per day at 5:00 p.m.? 2.7.2. If the answer to the previous question is “no,” please state what database to which the AM database is uploaded. 2.7.3. Is the AM database available to be queried within the Data Warehouseas part of the ICDA programs?? 2.7.4. If the answer to the previous question is “no,” please identify the databases and the location(s) of those the data bases which will be queried by the ICDA programs.

Utility Response 2.7: Response to Q 2.7.1: Please see the response to Question 2.5.4. Response to Q 2.7.2: See response to 2.7.1. Response to Q2.7.3: Yes. Response to Q 2.7.4: See response to 2.7.3.

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DATE RESPONDED: MARCH 6, 2018

2.8. The response to SCGC-01, Q.1.4.5, states: “The data base containing the AM interval data does not contain information related to the identity of the entity that procures gas on behalf of our customers.” 2.8.1. Does the CIS database contain information identifying the entity that procures gas on behalf of core customers? 2.8.2. If the answer to the previous question is “no,” please identify the database that contains information identifying the entity that procures gas on behalf of core customers? 2.8.3. Has the CIS database been uploaded to the Data Warehouse? 2.8.4. If the answer to the previous question is “yes,” please state how frequently the CIS database is uploaded to the Data Warehouse? 2.8.5. Can the CIS database be queried simultaneously with the AM interval data within the Data Warehouse database/programming environment?

Utility Response 2.8: Response to Q 2.8.1: Yes. Response to Q.2.8.2: See response to 2.8.1. Response to Q. 2.8.3: Yes, but only particular categories of data needed for analytics is uploaded from the CIS database Not all data from CIS is in the Data Warehouse. Response to Q. 2.8.4: A daily upload of the prior day CIS data occurs for master data and transactional data (bills, payments, service orders, etc.) and a monthly upload occurs for revenue data. Response to Q.2.8.5: No, CIS does not contain AM interval data. Data Warehouse was created for the purposes of analytics. .

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DATE RESPONDED: MARCH 6, 2018 2.9. Witness Christopher Olmsted states in Workpaper SCG-26-CWP at page 193 of 871

regarding ICDA:

Upon implementation of this integrated data solution business units in scope will have the following opportunities to realize the following benefits: •Improved analytics around inaccurate bills, process billing, exceptions/resolutions(failed edits) with the opportunity to reduce the number of monthly billing exceptions •Increase in paperless billing rate

2.9.1. Is the CIS currently used to prepare customer bills?

2.9.2. If the answer to the previous question is “no,” please state what system is used to prepare customer bills.

2.9.3. If the ICDA is to improve the billing systems as described in the above quote would the ICDA utilize information from the CIS that is uploaded into the Data Warehouse?

2.9.4. How frequently would the CIS data be uploaded to the Data Warehouse in order to enable the ICDA to improve the billing systems?

2.9.5. If the ICDA would not utilize information from the CIS that is uploaded into the Data Warehouse, please describe what databases that the ICDA would access to improve billing functions without utilizing information from the CIS and state what programming environment the ICDA would use to complete its improvement of the billing functions.


Response to Q.2.9.1: Yes.

Response to Q 2.9.2: See response to Question 2.9.1.

Response to Q.2.9.3: SoCalGas objects to this request on the grounds that it misconstrues the testimony in Exhibit SCG-19-R at MHB-73 to MHB-74. Subject to and without waving this objection, SoCalGas responds as follows: The testimony says ICDA will improve the “analytics around inaccurate bills, process billing, exceptions/resolutions (failed edits) with the opportunity to reduce the number of monthly billing exceptions,” not the billing system itself.

Response to Q.2.9.4: SoCalGas objects to this request on the grounds that it misconstrues the testimony in Exhibit SCG-19-R at MHB-73 to MHB-74. Subject to and without waving this objection, SoCalGas responds as follows: See response to Question 2.8.4.

Response to Q.2.9.5: See response to Q.2.9.3 above.

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Attachment M: A.17-10-007, Applicants’ Response to SCGC-03


SEU RESPONSE DATE RECEIVED: APRIL 2, 2018

DATE RESPONDED: APRIL 16, 2018

3.1 With respect to the Applicants’ response to SCGC-SEU-02, Q.2.8.1, is the information

identifying the entity that procures gas on behalf of core customers uploaded to the Data

Warehouse?


a. No, this information is not uploaded to the Data Warehouse.

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DATE RESPONDED: APRIL 16, 2018 3.2 If the answer to the previous question is “yes,” please state how frequently the information

identifying the entity that procures gas on behalf of core customers is uploaded to the Data

Warehouse.


Not applicable, see the response to Question 3.1

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3.3 With respect to the response to SCGC-SEU-02, Q.2.8.3, please state what data constitutes

“master data”, defining each category that is included in the data uploaded to the Data

Warehouse from the CIS database on a daily basis.

Utility Response 3.3: SoCalGas objects to this request pursuant to Rule 10.1 of the Commission’s Rules of Practice and Procedure, on the grounds that the request seeks the production of information that is outside the scope of this proceeding and neither relevant to the subject matter involved in the pending proceeding nor likely reasonably calculated to lead to the discovery of admissible evidence in this proceeding. Subject to and without waiving the foregoing objections, SoCalGas responds as follows: As used in SoCalGas’ response to SCGC-SEU-02, Q.2.8.3, “master data” is a single source of common business data used across multiple systems, applications, and/or processes.

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3.4 With respect to the response to SCGC-SEU-02, Q.2.8.4:

3.4.1 Please explain in detail what is meant by “revenue data” and state what other data (e.g.,

customer number or identifier) is included in the data that is uploaded to the Data Warehouse

on a monthly basis.

3.4.2 Does the data uploaded to the Data Warehouse include the heat content of the gas that

is used in calculating the amount of therms billed to customers during the previous month?

3.4.3 If the answer to the previous question is “no,” is the heat content of the gas that is used

in calculating the amount of therms billed to customers uploaded to the Data Warehouse

from any other source?

Utility Response 3.4: 3.4.1 As used in SoCalGas’ response to SCGC-SEU-02, Q.2.8.4, “revenue data” is the monthly as-billed consumption for SoCalGas customers. It contains details such as the billing period (start and end date), bill account, facility, service point, rate (tariff), CCF total (hundred cubic feet), Therm total, total gas charges, total non-gas charges, and total bill amount.

3.4.2 SoCalGas objects to this request pursuant to Rule 10.1 of the Commission’s Rules of Practice and Procedure, on the grounds that the request calls seeks the production of information that is outside the scope of this proceeding and neither relevant to the subject matter involved in the pending proceeding nor likely reasonably calculated to lead to the discovery of admissible evidence in this proceeding. 3.4.3 Subject to the objection set forth above in response to Question 3.4.2, SoCalGas responds as follows. Not applicable, see response to Question 3.4.2.

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3.5 With respect to the response to SCGC-SEU-02, Q.2.8.5:

3.5.1 Please confirm that the data from the CIS database that is uploaded to the Data

Warehouse can be queried simultaneously with the AM interval data within the Data

Warehouse.

3.5.2 How long would it take to run a query that simultaneously selects a portion of data from

the CIS data that has been uploaded to the Data Warehouse and all of the AMI data that

has been uploaded to the Data Warehouse and writes the data to a new database within

the Data Warehouse converting the hourly reads of cubic feet to therms?

Utility Response 3.5: 3.5.1 Yes, the CIS data in the Data Warehouse can be queried with the AM interval data as it is

made available within the Data Warehouse.

3.5.2 How long it would take depends on the specific, detailed requirements for the query and the format of the “new database.”

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3.6. With respect to the response to SCGC-SEU-02, Q.2.5.4:

3.6.1. Please state what times during each day the “Data Warehouse initiates several

load processes that transfers hourly reads and usage data (in cubic feet, not therms) to the

Data Warehouse.”

3.6.2. Each time the Data Warehouse initiates the load processes, is all of the AMI data

that is present in the MDMS system for the previous Gas Measurement Day is uploaded

to the Data Warehouse or only some portion of the data?

3.6.3. If only some portion of the data is uploaded as described in the previous question,

please specify how that portion of the data is determined.

3.6.4. How long does it take to upload the data from the MDMS system to the Data

Warehouse?


SoCalGas objects to Question 3.6 under Rule 10.1 of the Commission’s Rules of Practice and Procedure on the grounds that the information sought by this request is not relevant to the scope of the subject matter involved in the pending proceeding and the burden, expense and intrusiveness of this request outweighs the likelihood that the information sought will lead to the discovery of relevant and admissible evidence within the scope of the pending proceeding.

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3.7. With respect to the response to SCGC-SEU-02, Q.2.4.6 to Q.2.4.8, based on SoCalGas’ experience during the previous three years, please state the expected percentage failure rate for MTUs transmitting their data.

Utility Response 3.7: SoCalGas AMI consistently reports on MTU transmission in its semi-annual reports1 to the Commission. The most recent Module Communication Status metric for MTUs “Missing All Reads” is 0.1% of the MTUs installed with network coverage.

1 https://www.socalgas.com/regulatory/A0809023.shtml

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https://www.socalgas.com/regulatory/A0809023.shtml




3.8 With respect to the response to SCGC-SEU-02, Q.2.2.4, are the modules randomly assigned to one of the six data transmittal schedules?



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3.9 If the answer to the previous question is “no,” please state the basis upon which the modules are assigned to one of the six data transmittal schedules.



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3.10. With respect to the response to SCGC-SEU-01, Q.1.4.6, does the witness have any reason to believe that such a query would not be possible? Utility Response 3.10: SoCalGas objects to this request pursuant to Rule 10.1 of the Commission’s Rules of Practice and Procedure, on the grounds that the request calls for speculation, and seeks the production of information that is outside the scope of this proceeding and neither relevant to the subject matter involved in the pending proceeding nor likely reasonably calculated to lead to the discovery of admissible evidence in this proceeding. Subject to and without waiving the foregoing objections, SoCalGas responds as follows:

See Supplemental Response to 1.4.6 on March 22, 2018.

Page 10



DATE RESPONDED: APRIL 16, 2018 3.11 If the answer to the previous question is “yes,” please state any reason that would make the witness believe that the query would not be possible. Utility Response 3.11: SoCalGas objects to this request pursuant to Rule 10.1 of the Commission’s Rules of Practice and Procedure, on the grounds that the request calls for speculation, and seeks the production of information that is outside the scope of this proceeding and neither relevant to the subject matter involved in the pending proceeding nor likely reasonably calculated to lead to the discovery of admissible evidence in this proceeding.

Page 11




3.12. With respect to the response to SCGC-SEU-01, Q.1.5., SoCalGas states its objection to the question “in that it assumes that ENVOY is not currently capable of changing certain attributes with sufficient time and funding as mandated by the Commission.”

3.12.1. Given the response to Q.1.5.1 that states: “As proposed in this Test Year 2019 General Rate Case (TY2019 GRC), the ENVOY enhancements address the foundational architecture only.” Would the enhancements to the ENVOY foundation architecture proposed in this proceeding be expected to enable future changes to ENVOY at a lower cost than would be possible with the current ENVOY architecture for a change such as enhancing customers’ ability to manage their nominations? 3.12.2. Given the response to Q.1.5.3 that states: “As proposed in this Test Year 2019 General Rate Case (TY2019 GRC), the ENVOY enhancements address the foundational architecture only.” Would the enhancements to the ENVOY foundation architecture proposed in this proceeding be expected to enable future changes to ENVOY at a lower cost than would be possible with the current ENVOY architecture for a change such as allowing core and/or noncore customers to see their Measurement Day burn early in the day following the metered Measurement Day? 3.12.3. Given the response to Q.1.5.5 that states: “As proposed in this Test Year 2019 General Rate Case (TY2019 GRC), the ENVOY enhancements address the foundational architecture only.” Would the enhancements to the ENVOY foundation architecture proposed in this proceeding be expected to enable future changes to ENVOY at a lower cost than would be possible with the current ENVOY architecture for a change such as notifying customers of their imbalance position for the previous Measurement Day on a daily basis? 3.12.4. Given the response to Q.1.5.7 that states: “As proposed in this Test Year 2019 General Rate Case (TY2019 GRC), the ENVOY enhancements address the foundational architecture only.” Would the enhancements to the ENVOY foundation architecture proposed in this proceeding be expected to enable future changes to ENVOY at a lower cost than would be possible with the current ENVOY architecture for a change such as allowing customers to trade their daily gas imbalances with other customers?

Utility Response 3.12.1-4: SoCalGas objects to this request and all of its subparts pursuant to Rule 10.1 of the Commission’s Rules of Practice and Procedure to the extent it seeks information that is neither relevant to the subject matter involved in this proceeding nor is reasonably calculated to lead to the discovery of admissible evidence for this proceeding.

Page 12



DATE RESPONDED: APRIL 17, 2018 Utility Response 3.12.1-4:-Contined SoCalGas also objects to this request on the grounds that it assumes facts not in evidence and lacks foundation in that it assumes that ENVOY is not currently capable of changing certain attributes with sufficient time and funding as mandated by the Commission, and calls for the speculation. Subject to and without waiving this objections, SoCalGas responds as follows: SoCalGas envisions that the proposed architectural enhancements to ENVOY included in its Test Year 2019 General Rate Case and discussed in Exh. SCG-13 at 25:8-20 and in response to SCGC-SEU-01, Q.1.5., should allow for future modifications of ENVOY at a lower cost compared to the current architecture foundation.

Page 13

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

SCGC-SEU DATA REQUEST-004

SDG&E-SOCALGAS 2019 GRC – A.17-11-007/8

SEU RESPONSE

DATE RECEIVED: APRIL 10, 2018


Regarding SCG-19R: Customer Services - Office Operations

4.1 With respect to the request for funding of the CTAs Customer Data Exchange in SCG-19,

page MHB-70, please state:

4.1.1 How many CTAs currently serve core customers on the SoCalGas system?

4.1.2 How many core customers on the SoCalGas system are served currently by CTAs?

4.1.3 In percentage terms, how much of the core gas requirements are served by CTAs?


4.1.1 There are 22 active CTAs serving core customers on the SoCalGas system.

4.1.2 The CTAs serve 71,137 customer accounts.

4.1.3 CTAs make up 7.75% of the total core load.

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Regarding the Response to SCGC-SEU-002

4.2 Regarding the response to Q.2.5.1: Please confirm that the MDMS data set contains the MTU

identifier in addition to the hourly meter data.


SoCalGas objects to Question 4.2 under Rule 10.1 of the Commission’s Rules of Practice and

Procedure on the grounds that the information sought by this request is not relevant to the scope

of the subject matter involved in the pending proceeding and the burden, expense and

intrusiveness of this request outweighs the likelihood that the information sought will lead to the

discovery of relevant and admissible evidence within the scope of the pending proceeding.

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SEU RESPONSE



4.3 Regarding the response to Q.2.5.4: Does the MDMS data set that is uploaded daily to the

Data Warehouse contain all of the hourly metering history that is available for a given MTU

identifier in addition to the hourly metering data for that MTU identifier for the previous

metering day?







Page 3



SEU RESPONSE



4.4 If the answer to the previous question is “no,” please define the portion of the metering

history that is available for a given MTU identifier.







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4.5 In terms of a simultaneous query of the CIS data that has been uploaded to the Data

Warehouse and the AMI data for the previous metering day that has been uploaded to the

Data Warehouse, how long would it take to run a query within the Data Warehouse for the

entire approximately 5.9 million customers that selects the identity of each core customer’s

gas provider from the CIS data and selects the AMI data for the previous metering day and

writes the MTU identifier, the identity of the gas provider, and the total of the hourly

metering data for the previous day to a new database within the Data Warehouse converting

the hourly reads of cubic feet to therms and compiling the results by the identity of the gas

providers, e.g., Gas Acquisition, CTA #1, CTA #2, etc., so a total daily metered use for the

previous metering day is determined for each gas provider?







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SEU RESPONSE



4.6 Would the time required to run the query scale down linearly, e.g., if 40 percent of the

customers were included in the query described previously would the time required be

approximately 40 percent of the time required for the previously described query?







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SEU RESPONSE



Regarding SDG&E-18: Customer Service Office Operations

4.7. With respect to the statement on page JDS-65: “The Smart Meter Systems Upgrade

project will upgrade the CE and MDMS and associated database hardware in order

to reduce the risk of catastrophic system failure and avoid significant costs

associated with system recovery and lost revenue.”

4.7.1. Regarding the CE (Collection Engine) and MDMS (Meter Data Management

System), does the proposal intend to upgrade the programming, software utilized

by the programming or hardware (computer systems) employed by the software

or some combination of these three?

4.7.2. What changes will be made to the associated database hardware under this

proposed upgrade?

4.7.3. How many times per day does the CE collect data from the gas meters under the

current system?

4.7.4. At what times each day does the CE collect data from the gas meters under the

current system?

4.7.5. Please describe each step taken by the CE as it collects metering data under the

current system.

4.7.5.1.Is the gas metering data collected separately from the electric metering

data or simultaneously for those customers having both a gas and an

electric meter?

4.7.5.2.Does each gas meter have a unique identifier?

4.7.5.3.Does each gas meter module have a unique identifier?

4.7.5.4.Does the CE collect the metering information from the gas meters or do

the gas meters send the metering information to the CE?

4.7.5.5.How much time is required for the CE to collect the data from all

individual gas meters?

4.7.5.6.Does the CE collect the data from the individual gas meters according to a

specified pattern?

4.7.5.7.If the answer to the previous question is “yes,” please describe the pattern and if

the answer to the previous question is “no,” please state whether the CE collects

the gas metering data in a random fashion.

4.7.6. How many times per day will the CE collect data from the gas meters under the

proposed system?

4.7.7. At what times each day will the CE collect data from the gas meters under the

proposed system?

4.7.8. Please describe each step that will be taken by the CE as it collects metering data

under the proposed system.

4.7.8.1.Under the proposed system will the gas metering data be collected

separately from the electric metering data or simultaneously for those

customers having both a gas and an electric meter?

4.7.8.2.Under the proposed system will the CE collect the metering information

from the gas meters or will the gas meters send the metering information

to the CE?

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SEU RESPONSE



Question 4.7 Continued:

4.7.8.3.How much time will be required for the CE to collect the data from all

individual gas meters?

4.7.8.4.Under the proposed upgrade, will the CE collect the data from the

individual meters according to a specified pattern?

4.7.8.5.If the answer to the previous question is “yes,” please describe the pattern

and if the answer to the previous question is “no,” please state whether the

CE will collect the metering data in a random fashion.

4.7.9. Please describe the steps that are taken by the CE in transferring the metering data

to the MDMS system under the current system.

4.7.9.1.Does the CE perform any verification processes under the current

structure?

4.7.9.2.If the answer to the previous question is “yes,” please list each of the

verification processes and state how much time is necessary to complete

these processes.

4.7.9.3.How many times during each day does the CE transfer metering data to

the MDMS under the current system?

4.7.9.4.If only a portion of the metering data is transferred at any one time, please

describe the data that is transferred specifying whether it is complete

records for the day for a given subset of gas meter modules or if it is

partial metering data for the day for all or a portion of the gas meter

modules.

4.7.9.5.Does the resulting metering database contained in the MDMS include the

unique identifier for the gas metering module or alternatively the gas

meter?

4.7.10. Please describe the steps that are taken by the CE in transferring the metering data

to the MDMS system under the proposed upgraded system.

4.7.10.1. Will the CE perform any verification processes under the proposed

upgraded structure?

4.7.10.2. If the answer to the previous question is “yes,” please list each of the

verification processes and state how much time will be necessary to

complete these processes.

4.7.10.3. How many times during each day would the CE transfer metering data

for the previous metering day to the MDMS under the proposed system?

4.7.10.4. If only a portion of the metering data is transferred at any one time,

please describe the data that would be transferred specifying whether it

will be complete records for the day for a given subset of gas meter

modules or if it will be partial metering data for the day for all or a

portion of the gas meter modules.

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SEU RESPONSE




4.7.10.5. Will the resulting metering database contained in the MDMS include the

unique identifier for the gas metering module or alternatively the gas

meter?

4.7.11. Under the current system, does the MDMS data contain all of the hourly metering

history that is available for a given gas meter module identifier (or gas meter

identifier) in addition to the hourly metering data for that gas meter module

identifier (or gas meter identifier) for the previous metering day?

4.7.12. Under the proposed system, will the MDMS data contain all of the hourly

metering history that is available for a given gas meter module identifier (or gas

meter identifier) in addition to the hourly metering data for that gas meter module

identifier (or gas meter identifier) for the previous metering day?


4.7.1 SDG&E objects to this request pursuant to Rule 10.1 of the Commission’s Rules

of Practice and Procedure, on the grounds that the request is vague and ambiguous with

respect to the term “the programming.” Subject to and without waiving the foregoing

objections, SDG&E responds as follows:

Both the software and hardware associated with CE and MDMS have been or will be

upgraded. This includes all application and database server hardware, server operating

systems, application and database management software, and system integrations in all

pre-Production and Production environments.

4.7.2 Both CE and MDMS databases are to be moved from shared IBM AIX frames to

newly provisioned Oracle Linux DB servers capable of supporting the latest version of

Oracle (12c) allowing for more resources to be allocated to each application DB instance

as data volumes grow.


of Practice and Procedure, on the grounds that the request seeks the production of

information that is outside the scope of this proceeding and neither relevant to the subject

matter involved in the pending proceeding nor likely reasonably calculated to lead to the

discovery of admissible evidence in this proceeding. Subject to and without waiving the

foregoing objections, SDG&E responds as follows:

See Testimony of Jerry Stewart, Application of SoCalGas and SDG&E Regarding

Feasibility of Incorporating Advanced Meter Data into the Core Balancing Process, A.17-

10-002.

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SEU RESPONSE












10-002.









10-002.

4.7.5.1 SDG&E objects to this request pursuant to Rule 10.1 of the Commission’s Rules







Feasibility of Incorporating Advanced Meter Data Into the Core Balancing Process,

A.17-10-002.

4.7.5.2 Yes.

4.7.5.3 Yes.

Page 10



SEU RESPONSE












10-002.









10-002.







See Testimony of Jerry Stewart Application of SoCalGas and SDG&E Regarding


10-002.







Page 11



SEU RESPONSE






10-002.







See Testimony of Jerry Stewart Application of SoCalGas and SDG&E Regarding


10-002.









10-002.







There will be no changes from the previous system.







Page 12



SEU RESPONSE




There will be no changes from the previous system. Data will continue to be collected

together.





























Page 13



SEU RESPONSE












10-002.


of Practice and Procedure, on the grounds that the request is vague and ambiguous with

respect to the term “verification processes” and it seeks the production of information

that is outside the scope of this proceeding and neither relevant to the subject matter

involved in the pending proceeding nor likely reasonably calculated to lead to the

discovery of admissible evidence in this proceeding.

4.7.9.2 N/A

4.7.9.3 Metering data is transferred to the MDMS as it is received from meters

throughout the day. This happens during normal interrogation windows as well as during

daily efforts to fill electric meter interval data gaps. These gap-fill efforts occur

throughout the day.

4.7.9.4 N/A







Yes, in the current version both the gas meter id and the meter module MAC address

reside in the MDMS.

4.7.10 There is no change from the previous system.

Page 14



SEU RESPONSE




4.7.10.1 SDG&E objects to this request pursuant to Rule 10.1 of the Commission’s

Rules of Practice and Procedure, on the grounds that the request is vague and ambiguous

with respect to the term “verification processes” and it seeks the production of




4.7.10.2 N/A

4.7.10.3 There is no change from the previous system.

4.7.10.4 N/A

4.7.10.5 SDG&E objects to this request pursuant to Rule 10.1 of the Commission’s

Rules of Practice and Procedure, on the grounds that the request seeks the production of





In the new version of MDMS only the gas meter module MAC address will reside in

MDMS.









10-002.







Page 15



SEU RESPONSE






10-002.

Page 16



SEU RESPONSE



4.8. With respect to the statement on page JDS-71: “The Enhanced Network Analytics

Project would build a Smart Meter Analytics platform that enables efficient and

robust data processing, and enhanced reporting and analytics capabilities required to

maintain a reliable Advanced Metering Infrastructure (AMI) network. The platform

will integrate customer information, meter data and attributes, distribution assets,

weather data, and data from various sources that is required to proactively report,

analyze, and prioritize data quality issues and meter exceptions. This application

would also establish the foundation required to quickly scale and store new data,

develop new analytical dashboards, and provide necessary reporting.”

4.8.1. Where does SDG&E currently maintain and analyze its customer information,

e.g., does SDG&E have a separate Customer Information database?

4.8.2. Does the Customer Information database contain information about customers

that includes service address (location of meter), billing address, whether the

customer is core or noncore, rate schedule(s) that apply to customer for billing

purposes, and for core customers the identity of the provider of gas

procurement services?

4.8.3. Does the Customer Information database contain a unique identifier for the

gas meter and a separate unique identifier for the gas meter module?

4.8.4. Does SDG&E currently use the Customer Information database to calculate

customer bills or does SDG&E currently use the MDMS system to calculate

customer bills?

4.8.5. Does SDG&E currently have the ability to simultaneously query customer

information and AMI data?

4.8.6. If the answer to the previous question is “yes,” please describe the database

environment within which these queries occur.

4.8.7. Does SDG&E already have its own Data Warehouse in use?

4.8.8. If the answer to the previous question is “no,” does SDG&E use SoCalGas’

Data Warehouse?

4.8.9. In terms of a simultaneous query of the customer information data that has

been uploaded to the Data Warehouse and the AMI data for the previous

metering day that has been uploaded to the Data Warehouse, how long would

it take to run a query within the Data Warehouse for the entire approximately

0.9 million gas customers that selects the identity of each core customer’s gas

provider from the customer information data and selects the AMI data for the

previous metering day and writes the gas module (or gas meter) identifier, the

identity of the gas provider, and the total of the metering data for the previous

day to a new database within the Data Warehouse converting the meter reads

of cubic feet to therms and compiling the results by the identity of the gas

providers, e.g., Gas Acquisition, CTA #1, CTA #2, etc., so a total daily

metered use for the previous metering day is determined for each gas

provider?

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SEU RESPONSE




4.8.10. How would the “Smart Meter Analytics platform” described above be

different from a Data Warehouse system, e.g., the Data Warehouse maintained

by SoCalGas for use in analyzing its AMI data in conjunction with data from

other sources, such as its Customer Information System?

4.8.11. Does SDG&E currently have the capability of providing AMI data to

SoCalGas on a daily basis?


4.8.1 SDG&E maintains customer information in the DB2 database supporting the

Customer Information System (CIS). For reporting and analysis of customer information,

SDG&E currently utilizes its Enterprise Data Warehouse (EDW).

4.8.2 The DB2 database contains the customer service address, general location of the

meter, billing address, and rate schedule. The DB2 database does not contain gas

procurement services information.

4.8.3 Yes.






4.8.5 Yes, SDG&E has the ability to simultaneously query customer information and

AMI data, but that query would be limited to the energy consumption information that is

available at that moment in time.

4.8.6 Microsoft SQL Server Enterprise Data Warehouse (EDW).

4.8.7 Yes.

4.8.8 N/A


of Practice and Procedure, on the grounds that the request lacks foundation, is an

incomplete hypothetical, and seeks the production of information that is outside the scope

of this proceeding and neither relevant to the subject matter involved in the pending

proceeding nor likely reasonably calculated to lead to the discovery of admissible

evidence in this proceeding.

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SEU RESPONSE





of Practice and Procedure, on the grounds that the request lacks foundation and seeks the

production of information that is outside the scope of this proceeding and neither relevant

to the subject matter involved in the pending proceeding nor likely reasonably calculated

to lead to the discovery of admissible evidence in this proceeding. Subject to and without

waiving the foregoing objections, SDG&E responds as follows:

The Smart Meter Analytics platform integrates numerous AMI data sources (beyond

energy consumption information) that are not integrated with either the SDG&E

Enterprise Data Warehouse system or DB2 database.






Page 19

Attachment O: A.17-10-007, Applicants’ Response to SCGC-05



SEU RESPONSE


DATE RESPONDED: MAY 7, 2018

Regarding SCG-19R: Customer Services - Office Operations

5.1. With respect to the statement on page MHB-73:

ICDA is a strategic priority and enabler of multiple projects within the

Customer Services and Customer Solutions organizations. ICDA’s goal is

to develop data analytics capabilities (people, technology and process) that

enable the future vision of SoCalGas’ customer analytics. The technology

solution accommodates platforms, tools and various sources of customer

data, increased data volume generated from Advanced Meter interval data,

customer self-service transactional data and external third-party data. Data

Analysts, Data Scientists and Data subject matter-experts (people) will use

data to analyze customer behavioral patterns, trends, and preferences during

the customer evolution process (starting service, requesting service orders,

program participation, remittance processing, transferring services, among

others).

And the discussion about Phase 3 of the ICDA project, which occurs on page MHB-74 stating

that “the objective of this project is continue the enhancement of the ICDA.” The following

questions relate to the enhancement of the ICDA system so that it would be capable of producing

information that would enable the core to balance to actual burn from the previous day.

5.1.1. Please state the estimated cost required to produce the programming necessary to

expand the master data that is uploaded from the CIS system to the Data Warehouse

on a daily basis so that this data includes the identity of the agent that procures gas on

behalf of each core customer.

Utility Response 5.1.1:

SoCalGas objects to the request under Rule 10.1 of the Commission’s Rules of Practice and





SoCalGas further objects to this request on the grounds that the request is vague and ambiguous,

and burdensome to the extent that the request asks SoCalGas to design and estimate costs for a

new system or product in response to a discovery request, which is an inappropriate use of the

discovery process.

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SEU RESPONSE



Regarding SCG-13: Gas Control and System Operations

5.2. With respect to the statements on page DKZ-25:

SoCalGas proposes to replace the existing ENVOY® system from the

ground up, making the system more flexible and customer friendly,

allowing it to adapt quickly to regulatory changes and enhancing the

customer experience. Modularizing the architecture of ENVOY® will make

it more configurable. The individual functions and business rules that are

processed in the system will be coupled loosely allowing for individual

updates and deployments, permitting Gas Scheduling to quickly and

efficiently comply with regulatory mandates.

and

The SoCalGas ENVOY® Next Generation Project entails a fully revamped

interface and navigational menus, expanded to provide customers with up-

to-date information, additional data querying functions and reporting,

additional accessibility (neutral web browser use and mobile platforms),

customizable account functions, and stronger web security. These additional

capabilities were developed based on input from ENVOY® service users.

5.2.1. Please state the estimated cost required to prepare the programming that is required to

further enhance the ENVOY system so that it is capable of providing daily imbalance

trading for customers where imbalances are not allowed to be traded considering gas

in storage or the existence of customer storage rights.

5.2.2. Please state the estimated cost required to prepare the programming that is required to

further enhance the ENVOY system so that it is capable of providing daily imbalance

trading for customers where imbalances are allowed to be traded considering gas in

storage or the existence of customer storage rights.

Page 2



SEU RESPONSE




5.2.1. SoCalGas objects to this request under Rule 10.1 of the Commission’s Rules of Practice

and Procedure to the extent it seeks the production of information that is neither relevant to the

subject matter involved in the pending proceeding nor is reasonably calculated to lead to the

discovery of admissible evidence. SoCalGas objects to this request on the grounds that it calls

for speculation. SoCalGas also objects to this request on the grounds that it is unduly

burdensome to the extent that the request asks SoCalGas to design and estimate costs in response

to a discovery request. Subject to and without waiving this objection, SoCalGas responds as

follows:

SoCalGas has not prepared an estimate to further enhance the ENVOY system with the

specifically described functionality.

5.2.2. See response to 5.2.1.

Page 3

Attachment P: A.17-10-007, Testimony of Rene F. Garcia, excerpts

Company: Southern California Gas Company (U 904 G) Proceeding: 2019 General Rate Case Application: A.17-10-____ Exhibit: SCG-17

SOCALGAS

DIRECT TESTIMONY OF RENE F. GARCIA

(ADVANCED METERING INFRASTRUCTURE (AMI))

October 6, 2017

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

Page 1

RFG-7

ADVANCED METERING INFRASTRUCTURE POLICY 1

Regulatory Background and Overview 2

Regulatory Background 3

As stated above, the Application requested authorization to convert approximately six 4

million customer meters to advanced metering. On April 8th, 2010, the Commission authorized 5

the project in D.10-04-027. Shortly thereafter, SoCalGas’ Advice Letter (AL) 1410 was 6

authorized to establish the Advanced Metering Infrastructure Balancing Account (AMIBA) to 7

record O&M and capital-related costs and to implement a component of customer rates through 8

the AMI project deployment period (2010 – 2017). 9

AMI Overview 10

SoCalGas’ AMI deployment consists of three primary components: 1). Meter 11

Transmission Units (MTUs) installed on nearly 6 million gas meters; 2). nearly 4,600 Data 12

Collector Units (DCUs) to be constructed throughout the service territory by TY 2019; and 3). 13

back-office systems that allow for the collection and management of automated meter readings 14

for billing (e.g. Headend (HE) and Meter Data Management System (MDMS)). Figure RG-1 15

provides an overview of the AMI data flow: 16

FIGURE RG-1 17 AMI Data Flow Overview 18

19

1. The MTU turns on and securely transmits gas usage information to the DCUs for 20

a fraction of a second a day 21

2. DCUs wirelessly transmit MTU usage from the meter to SoCalGas’ back-office 22

systems. 23

3. SoCalGas’ systems process usage data and calculate bills 24

Page 2

RFG-8

4. Customers are then provided access to their gas usage and billing data on the 1

internet or from their mobile devices. 2

An MTU is a communications device that automatically and securely transmits hourly 3

gas meter readings to our DCUs, which in turn transmit the gas meter readings to our back-office 4

systems (e.g. MDMS and HE) and billing department, eliminating the need for manual meter 5

reading. 6

While gas usage is still measured by the analog meter as it was prior to adding the AMI 7

technology, the MTU is applied (retrofitted) to the meter to securely transmit hourly meter 8

readings wirelessly through SoCalGas’ data communications network. The MTU is off most of 9

the time, turning on for only a fraction of a second per day (less than two minutes total per year). 10

MTUs are battery powered and most are expected to last up to 20 years. 11

The AMI communication network will include nearly 4,600 DCUs by TY 2019 across 12

the SoCalGas service territory. The DCUs receive the meter reading data from the MTUs 13

installed on each meter. The data is encrypted and transmitted wirelessly across a licensed 14

frequency from the MTU to the DCU. The specific DCU locations, referred to as design points, 15

take into account the location of the approximately six million meters, the topography of the 16

surrounding area, and the influence of the built environment on the transmission of the radio 17

signal.6 DCUs can be placed within a 500-foot radius of a design point. Most MTUs will 18

communicate with at least three DCUs. 19

SoCalGas generally installs DCUs on SoCalGas owned poles or on local government/3rd 20

party owned street lights. When SoCalGas installs a DCU on its own pole, the DCU is solar-21

powered and is provided back-up power via internal batteries which are expected to last five 22

years. When a DCU is installed on a street light, the DCU is most often powered by electricity 23

from the street light. When a DCU is attached to a local government/3rd party street light or 24

other type of asset, SoCalGas negotiates a contract with the asset owner which usually includes a 25

fee to lease the space on the asset and an energy rate for the electricity to power the DCU, when 26

applicable. 27

The third component of the infrastructure includes the AMI Information Technology (IT) 28

systems, including the Head End (HE) and the Meter Data Management System (MDMS). 29

6 MTUs and the associated network communications system operate in the 450 to 470 megahertz (MHz) bands and 800/1900 cellular frequency, respectively.

Page 3

RFG-9

Meter reading data from the MTU is communicated to the DCUs and then transmitted to these 1

systems. Daily and hourly natural gas usage data is then made available on a next day basis 2

though SoCalGas’ My Account online customer portal and the SoCalGas Mobile App, providing 3

customers the opportunity to manage their usage and to potentially conserve energy and reduce 4

their monthly bills.7 5

Deployment Status 6

The following section provides information regarding the AMI deployment status, 7

including accomplishments through June, 2017 and on-going challenges such as local 8

jurisdiction permitting issues preventing SoCalGas from completing the DCU network, and 9

challenges that will preclude SoCalGas from completing its curb meter MTU deployment by the 10

end of 2017. 11

Deployment Status as of June 30th, 2017 12

SoCalGas’ AMI deployment is nearly complete. As of June, 2017, nearly 5.9 million 13

meters have been retrofitted with an MTU, representing 99 percent of total meters to be upgraded 14

with the AMI technology by TY 2019. Over the 4.5 years of AMI meter deployment, AMI field 15

installers have operated out of nineteen separate AMI warehouses, spread across SoCalGas’ 16

service territory.8 Of the nearly 5.9 million meters with MTUs, nearly 99 percent of those are 17

communicating with the AMI network, no longer requiring manual meter reading and are using 18

AMI meter readings for billing – an indication that the various components of the AMI, 19

including MTUs, DCUs and back-office systems, are integrated and operating effectively. 20

With AMI data, customers are now able to monitor their hourly gas usage on a next-day 21

basis and can adjust their usage to save energy and potentially reduce their monthly bills. 22

Additionally, residential conservation “behavior change” program treatments administered by the 23

AMI project produced natural gas savings of almost 1.5 percent amongst customers treated in the 24

2015-2016 heating season campaign and 1.6 percent for customers treated during the most recent 25

2016-2017 campaign. 26

7 This same usage information is also made available to SoCalGas customer service representatives in the Customer Contact Center to assist customers with billing and usage-related inquiries. 8 Installation warehouses are workforce hubs located and leased specifically for AMI related, meter installation operations. By the end of 2017, all remaining warehouse operations will be complete and the locations will be closed.

Page 4

Attachment Q: SoCalGas Rule 32, excerpts

SOUTHERN CALIFORNIA GAS COMPANY Revised CAL. P.U.C. SHEET NO. 50951-G LOS ANGELES, CALIFORNIA CANCELING Revised CAL. P.U.C. SHEET NO. 48975-G

Rule No. 32 Sheet 1 CORE AGGREGATION TRANSPORTATION

(Continued) (TO BE INSERTED BY UTILITY) ISSUED BY (TO BE INSERTED BY CAL. PUC)

ADVICE LETTER NO. 4719 Lee Schavrien DATE FILED Dec 1, 2014DECISION NO. 14-08-043 Senior Vice President EFFECTIVE Dec 1, 20141C13 RESOLUTION NO.

A. GENERAL The terms and conditions of this Rule shall apply to Core Transport Agents (CTAs) who are also known as Energy Service Providers (ESPs), and their end-use customers (Core Transportation Customers), as defined in Southern California Gas Company's (SoCalGas) Rule No. 1. The specific requirements for Core Transportation Customers are described in each core transportation rate schedule. The transportation of customer-owned gas in conjunction with service under this Rule is subject specifically to the terms and conditions of Rule No. 30, Transportation of Customer-Owned Gas, and Rule No. 23, Continuity of Service and Interruption of Delivery. The terms and conditions of Core Transportation Service as well as the specific rights and obligations of CTAs, Core Transportation Customers, and SoCalGas with regard to Core Transportation Service have been updated in this Rule to reflect CPUC D.98-02-108, which conforms the customer switching process for Core Transportation Service (also known as Core Aggregation Transportation or CAT Service) with the procedures and policies established for electric direct access and D.14-08-043, Decision Adopting Registration Standards for Core Transport Agents, which establishes requirements for CTAs as set forth in Public Utilities Code Sections 980 through 989.5.

1. Eligibility and Application for CTA Status

a. CTAs are required to complete an Agreement for Core Aggregation Service (Service Agreement), Form 6536-A, with SoCalGas and a Credit Application (Credit Application) that includes all financial information needed by SoCalGas to establish credit. CTAs are required to complete a new Credit Application on an annual basis and whenever the CTA's load increases by 25,000 therms per day or more from the CTA's load at the time the most recent Credit Application was completed. CTAs will be required to register with the CPUC in accordance with D.14-08-043 and Public Utilities Code Section 981.

b. Registered and approved CTAs may provide service to customers eligible for Core Service, as

defined in Rule No. 1 in accordance with D.93-09-082. The aggregate load of customers served by each CTA must meet a minimum transport quantity of 250,000 therms annually. If a CTA's aggregated load falls below the 250,000 therms per year, the CTA will be given 90 days from notification to make up the deficient load. If sufficient load is not added within 90 days of the date of notification by SoCalGas, the CTA's contract will be terminated, at SoCalGas' sole discretion, and end-use customers served by the CTA will be able to authorize service from a different CTA or return to SoCalGas' Core Procurement Service.

c. Registered CTAs shall ensure that any person or entity performing marketing or sales activities, or

administering its service agreements on the CTAs’ behalf, complies with rules adopted by the CPUC pursuant to Public Utilities Code Sections 980 through 989.5.

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(Continued)



A. GENERAL (Continued) 1. Eligibility and Application for CTA Status (Continued)

d. The term of the Service Agreement between a CTA and SoCalGas is 12 months, beginning with the first calendar day of the month after the Service Agreement is accepted by SoCalGas, and then month-to-month thereafter, until terminated as set forth in section C.5. below.

2. Changing Customer Status to Core Transportation Service

a. Eligibility for Program service is limited to customers eligible for Core Service, as defined in Rule

No. 1, in accordance with D.93-09-082. b. CTAs communicate changes in customer's status to SoCalGas via successful submission of an

electronic Direct Access Service Request (DASR). By submission of the DASR, the CTA warrants that the customer being enrolled in the Transportation Service program by the DASR:

(1) Has been informed of, and consents to all terms and conditions of SoCalGas' Core

Transportation Service; (2) Intended to change their status to "Core Transportation Service" and receive gas

procurement and related services from that specific CTA; (3) Has authorized the CTA to act on the customer's behalf in various gas procurement

activities; and, (4) Has authorized SoCalGas to release the customer's current and historic gas consumption

information to that specific CTA.

c. CTAs will maintain a signed customer contract (which includes customer acknowledgments and indemnification of SoCalGas as described in the Service Agreement) or records of independent third party verification in the manner set forth for requesting electronic direct access service in the Public Utilities Code Section 366.5. In accordance with D.14-08-043 and Public Utilities Code Section 983, the CPUC shall accept, compile and attempt to informally resolve consumer complaints regarding CTAs.

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(Continued)



A. GENERAL (Continued) 6. Taxes The CTA shall pay the applicable Utility User's Tax, and any other fees and taxes applicable within

the city or political subdivision where the gas is actually used unless otherwise provided for in a specific ordinance or other legislative ruling. For those customers located in Los Angeles county, pursuant to Los Angeles City Ordinance No. 168164, dated August 4, 1992, SoCalGas shall collect the user tax for all gas delivered through the gas system for transportation service customers and consumed in Los Angeles County.

7. Applicable Contract Provisions All contracts and customer authorizations of CTAs under this Rule shall be subject to Rule No. 4,

except as set forth below. DASRs and Customer Authorizations shall be deemed to be "contracts for gas service between CTA and Core Transportation Service Customer" for purposes of applying Rule No. 4 to this Rule: a. Damages SoCalGas shall not be assessed any special, punitive, consequential, incidental, or indirect

damages, whether in contract or tort, for any actions or inactions arising from or related to the Program.

b. CPUC Jurisdiction The contracts and authorizations pertaining to Transportation Only Service under this Rule, shall

at all times be subject to such changes or modifications by the CPUC as said Commission may, from time to time, direct in the exercise of its jurisdiction.

8. Contract Quantities

SoCalGas will assign a Daily Contracted Quantity (DCQ) on a monthly basis. The DCQ will be calculated using the following formula:

DCQ = A / B x C Where: "A" = CTA group's most recent twelve months historical consumption, "B" = Most recent twelve months deliveries on SoCalGas' system for the

customer class, and "C" = Utilities Authorized Core Cold Year Throughput

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(Continued)



D. DELIVERY OF GAS 1. Transportation of Customer Owned Gas CTAs participating in the Program will perform gas deliveries pursuant to the provisions and

conditions set forth in Rule No. 30, Transportation of Customer Owned Gas. 2. Imbalance Service The CTA is responsible for balancing transportation services with the customer’s end-use

consumption. The CTA is responsible for managing the imbalances of the end-users through means which include participation in the Utility’s Imbalance Trading Program pursuant to the provisions of Schedule No. G-IMB. Imbalances will be calculated on an aggregated customer basis, not by individual account or delivery point. Imbalances will be determined by comparing the amount of gas delivered to the Utility and the amount of gas actually consumed by the customers.

The CTA’s DCQ will be used as a proxy for gas actually consumed by their customers. Immediately

each month when actual meter usage information becomes available, an adjustment to the CTA’s imbalance account will be made to account for any differences between actual consumption of its customers and the DCQ.

The CTA shall be responsible for all imbalance charges, including any Utility Users Tax. The CTA

may pool the positive and negative imbalances of its customers in order to avoid or minimize imbalance charges

3. Backbone Transportation Service CTAs may receive Backbone Transportation Service by utilizing Schedule No. G-BTS. CTAs will

have the set-aside option, under Schedule No. G-BTS, to acquire firm Backbone Transportation Service during the open season process.

E. STORAGE RIGHTS AND OBLIGATIONS 1. Allocation of Storage Rights Storage rights and costs will be allocated to each CTA by SoCalGas in the same proportion as

storage costs are allocated to the customer classes represented by each CTA in SoCalGas' core transportation rates based on the prorata share of the Utility Gas Procurement Department allocated rights.

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(Continued)



E STORAGE RIGHTS AND OBLIGATIONS (Continued) 2. Storage Injection and Withdrawal Rights and Obligations CTAs are given a proportionate share of injection rights from April 1 through October 31 and,

withdrawal rights from November 1 through March 31. The CTA is responsible for storage injection and withdrawal rights pursuant to the provisions of Rule No. 30, Transportation of Customer-Owned Gas and G-IMB.

Gas in storage to meet core reliability cannot be used to cure and under-delivery during an imbalance

trading period. 3. Monthly Storage Inventory Requirements CTAs will be assigned month-end storage targets for the months of October, January and February to

meet SoCalGas' storage targets and maintain minimum quantities to meet Abnormal Peak Day (APD) and cold year requirements. CTA storage targets will be assigned in a manner consistent with the Utility Gas Procurement Department.

This gas in storage may not be subject to encumbrances of any kind. CTAs will not be allowed to

withdraw gas below these month-end targets. CTA winter month storage minimums are based on a proportionate allocation of total core storage

requirements as specified for the Utility Gas Procurement Department. 4. Adding And Deleting Customers Storage rights will be adjusted on a monthly basis to account for the addition or deletion of

customers. When a CTA adds new customer(s) or customer(s) return to SoCalGas, gas stored on behalf of such customer(s) shall be automatically sold, at the current month's Adjusted Core Procurement Charge, G-CPA, set forth in Schedule No. G-CP, to the CTA or to SoCalGas to which the customer is transferring if the amount of gas stored on behalf of customer(s) exceeds a minimum threshold of 1,000,000 therms. To the extent that this automatic transfer of title does not occur, the CTA or SoCalGas will remain obligated to meet all applicable storage targets.

5. Secondary Market Opportunities

CTAs who hold firm storage rights in addition to those which are held to meet core reliability requirements may release all or a portion of those rights in the secondary market by utilizing Schedule No. G-SMT. Any release of storage capacity must provide SoCalGas with the option to recall any gas stored on behalf of its core customers, at SoCalGas’ discretion, if, in SoCalGas’ sole judgment, such storage is necessary to serve returning customer(s) defined Section E.4.

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(Continued)

(TO BE INSERTED BY UTILITY) ISSUED BY (TO BE INSERTED BY CAL. PUC)


E STORAGE RIGHTS AND OBLIGATIONS (continued) 6. Storage Gas Remaining in Inventory

Any quantity of storage gas that is in excess of the inventory rights remaining after: a) the CTA’s storage contract term expires; or b) the CTA trades away some or all of its inventory rights; or c) the CTA’s inventory rights are reduced by SoCalGas based on a reduction in the CTA’s customer load; or d) the CTA’s storage contract is terminated, for whatever reason, prior to the completion of the term of such contract shall be immediately purchased by SoCalGas at the applicable Buy-Back Rate stated in Schedule No. G-IMB. The Buy-Back purchase amount paid to the CTA may be reduced by any outstanding amounts owed by the CTA for any other services provided by SoCalGas.

F. CURTAILMENT In the event of curtailment, SoCalGas shall make every effort to maintain service to Core Transportation

Service customers. Such curtailment shall be effectuated in accordance with the provisions of Rule No. 23, Continuity of Service and Interruption of Delivery. Penalties for violations of curtailment shall apply as set forth in Rule No. 23.

G. SERVICES PROVIDED BY SOCALGAS SoCalGas shall read customer meters, send customers legally required notices and bill inserts in

accordance with Public Utilities Code Section 454(a), and provide customers with all other regular SoCalGas services. This includes direct billing, unless the customer specifies in the DASR that SoCalGas bill the CTA for all charges.

H. OTHER TARIFFS Service under this Rule is subject to the terms and conditions of SoCalGas' tariff schedules on file with

the CPUC, including all applicable contracts and agreements.

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Attachment R: SDG&E Rule 32, excerpts

Revised Cal. P.U.C. Sheet No. 20905-G

San Diego Gas & Electric Company San Diego, California Canceling Revised Cal. P.U.C. Sheet No. 12265-G

RULE 32 Sheet 1

CORE AGGREGATION TRANSPORTATION

(Continued) 1C10 Issued by Date Filed Dec 1, 2014 Advice Ltr. No. 2338-G Lee Schavrien Effective Dec 1, 2014 Senior Vice President Decision No. 14-08-043 Regulatory Affairs Resolution No.

In Decision 91-02-040, dated February 21, 1991 the California Public Utilities Commission (CPUC) authorized a three-year experimental transportation program for core customers who elect to aggregate their service requirements with other core customers for the purpose of transporting their gas supply. In Decision 94-04-027, dated April 6, 1994, the CPUC made the three-year program permanent and extended the pilot program rules until such date that permanent rules could be adopted. In Decision 95-07-048, dated July 19, 1995, the CPUC adopted a Settlement which evolved the interim rules of the program. The terms and conditions of this Rule reflect these decisions and shall apply to Core Transport Agents (CTAs) and where appropriate to the CTA's end-use customers served under Schedule GTCA, the UDC's service schedule for the core aggregation program. In Decision 98-02-108, dated February 19, 1998, the CPUC approved the Petition of Enron Corporation For Modification of D.95-07-048 to permit gas CTAs to switch gas customers from the incumbent UDC using electronic communication and processes consistent with those adopted for electric direct access. In Decision 01-12-018, dated December 11, 2001, the CPUC approved the SDG&E/SoCalGas Comprehensive Gas OII Settlement, which removed the 10% participation limit initially put in place in 1991 by Decision 91-02-040, and reduced the minimum transport volume from 250,000 to 120,000 therms per year. In Decision 14-08-043, dated August 28, 2014, the CPUC adopted Registration Standards for CTAs. CTAs shall be registered with the CPUC. Commission jurisdiction over CTAs is set forth in Public Utilities Code Sections 980 through 989.5 The terms and conditions of this Rule shall apply to CTAs who are also known as Aggregators, and their end-use customers (Core Transportation Customers), as defined in the UDC’s Rule No. 1.

The specific requirements for Core Transportation Customers are described in each core transportation rate schedule. The transportation of customer-owned gas in conjunction with service under this Rule is subject specifically to the terms and conditions of Rule No. 30, Transportation of Customer-Procured Gas, Rule No. 14, Shortage of Gas Supply Interruption of Delivery, Priority of Service, Schedule G-IMB and the charges or credits associated with these rules. The UDC shall not be liable to the customer for any damages caused to the customer by any failure by CTA to comply with the UDC’s rules and tariffs, the CTA Agreements (Form 142-1859 and Attachment D of 142-1859) and associated legal and regulatory requirements. Pursuant to D.14-08-043 and Public Utilities Code Section 983, the CPUC shall accept, compile and attempt to informally resolved consumer complaints regarding CTAs.

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RULE 32 Sheet 2



A. GENERAL

1. Application for Service

The CTA shall be required to complete a “Request For Core Transportation-Only Services," Form 142-1859, agreement with the UDC. CTAs offering core aggregation service to residential or small commercial customers are required to register with the CPUC in accordance with D.14-08-043 and Public Utilities Code Section 981. The CTA may use one of two options for enrolling individual core gas customers in the CTA's aggregation group: 1) submit a customer and CTA signed Attachment A, "Direct Access Service Request (DASR) For Core Aggregation”, or, 2) submit a DASR electronically if the customer’s enrollment was authorized by independent third-party verification in accordance with California Public Utilities Code Section 366.5. All hard-copy Attachment As or electronically submitted DASRs by reference become part of the “Request For Core Transportation-Only Services” agreement between the CTC and the UDC, subject to the terms and conditions stated in this Rule and Schedule GTCA.

a. The term of the CTA Agreement shall be 12-months, beginning on April 1 and

ending on March 31, and shall automatically renew for subsequent 12-month periods unless terminated by either party with at least thirty (30) days written notice prior to the Agreement's anniversary date. A new CTA may start on the first day of any month, but the term of their initial Agreement will always terminate on March 31.

b. The initial load of customers served by the CTA must meet a minimum transport

volume of 120,000 therms annually. If a CTA's group load falls below 120,000 therms per year, the CTA will be given 90 days from notification to replace the deficient load. If the deficient load is not replaced, the CTA's contract will be subject to termination.

c. CTAs may add members to their group by: 1) submitting a hard copy Attachment A,

"Direct Access Service Request (DASR) For Core Aggregation," signed by the customer and CTA, properly identifying the gas account to be added. Or, 2) submitting an electronic gas direct access service request (DASR) that has been independent third-party verified.

d. Registered CTAs shall ensure that any person or entity performing marketing or

sales activities, or administering its service agreements on the CTAs behalf, complies with rules adopted by the CPUC pursuant to Public Utilities Code Sections 980 through 989.5

2. Direct Access Service Request (DASR) Process a. Eligibility for Core Transportation Program service is limited to customers eligible for

Core Service, as defined in Rule No. 1.

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RULE 32 Sheet 3



A. GENERAL (Continued) 2. Direct Access Service Request (DASR) Process (Continued) b. The DASR process described herein is used equally for customer’s electric and gas

Direct Access elections, customer-initiated returns to default UDC service and CTA-initiated termination of a customer agreement. CTAs must execute the “Request For Core Transportation-Only Services” agreement (Form 142-1859) before submitting DASRs for core aggregation service.

c. A separate DASR must be submitted for each service account. Upon request, the

UDC will provide timely updates on the status of the DASR processing to the submitting CTA and customer. A single DASR may be use to enroll both electric and gas service into direct access, when both services are on a single account.

d. By submission of the DASR, the CTA warrants that the customer being enrolled in

the Transportation Service program by the DASR:

(1) Has been informed of, and consents to all terms and conditions of UDC’s Core Transportation Service;

(2) Intended to change their status to "Core Transportation Service" and receive gas procurement and related services from that specific CTA;

(3) Has authorized the CTA to act on the customer's behalf in various gas procurement activities; and,

(4) Has authorized UDC to release the customer's current and historic gas consumption information to that specific CTA.

e. CTAs will maintain a signed customer contract (which includes customer

acknowledgments and indemnification of UDC) or records of independent third party verification in the manner set forth for requesting electronic Direct Access service in the Public Utilities Code, Section 366.5.

f. DASRs must identify the gas service account participating in Direct Access,

including its billing service election. A DASR that does not contain this information is materially incomplete.

g. DASR forms will be available through electronic means (e.g., the UDC’s website;

www.sdge.com).

h. A DASR shall not be submitted to the UDC until three days after the verification required under Public Utilities Code Section 366.5 has been performed. It is the responsibility of the CTA to ensure that the requests to cancel service pursuant to Public Utilities Code Section 395 and D.14-08-043 are honored. If a customer cancels an agreement pursuant to Public Utilities Code Section 395, a DASR shall not be submitted for that customer. If a DASR has already been submitted, the submitting party shall, within 24 hours, direct the UDC to cancel the DASR. In accordance with Public Utilities Section Code Section 989.1, residential gas customers may cancel the DASR by midnight of the 30th day after the date the first bill for CTA service is received by the customer without penalty.

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RULE 32 Sheet 4



A. GENERAL (Continued) 2. Direct Access Service Request (DASR) Process (Continued)

i. The UDC will provide an acknowledgment of its receipt of the DASR to the CTA

within two (2) working days of its receipt. The UDC will exercise best efforts to provide, within three (3) working days thereafter (and no later than five (5) working days), the CTA and the customer with a DASR status notification informing them as to whether the DASR has been accepted, rejected or deemed pending for further information. As of July, 1998, the UDC will provide this DASR status notification within three (3) working days. If accepted, the switch date determined in accordance with paragraph k. of this section will be sent to the CTA, the former CTA if applicable, and the customer. If a DASR is rejected, the UDC will provide the reasons for the rejection. If a DASR is held pending further information, it shall be rejected if the DASR is not completed within eleven (11) working days following the status notification.

j. In accordance with the provisions of Rule 3, the UDC has the right to deny the

CTA’s request for service if the information provided by the applicant is false, incomplete, or inaccurate in any material respect.

k. If a submitted DASR complies with the DASR requirements, the DASR will be

accepted and scheduled for gas Direct Access implementation.

l. DASRs shall be handled on a first-come, first-served basis. Each request shall be time-stamped by the UDC.

m. If more than one DASR is received for a service account within a single DASR

processing period (16th of the month until the 15th of the following month), only the first valid DASR received will be processed in that period. All subsequent DASRs will be rejected.

n. Accepted DASRs that are received by the UDC on or before the 15th of the month

will be switched over no later than the next month’s scheduled meter reading date for that service account.

o. The UDC, CTA and customer, on mutual agreement, may agree to a different

service change date for the service changes requested in a DASR.

p. A DASR is submitted pursuant to the terms and conditions of the Request For Core Transportation-Only Services Agreement and this Rule, and will also be used to define the gas billing service that the CTA is providing the customer.

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RULE 32 Sheet 5



A. GENERAL (Continued) 2. Direct Access Service Request (DASR) Process (Continued)

q. Customers returning to UDC bundled service will follow the same process and

timing as DASRs to establish Direct Access service.

(1) CTAs requesting to return a Direct Access customer to UDC bundled service will submit a DASR and be responsible for the continued provision of the customer’s gas supply service, and billing services until the service change date. In this case, the CTA will also be responsible for paying any Commission approved DASR charge.

(2) Customer’s requesting return to UDC bundled service may do so either by

contacting their CTA or directly contacting the UDC. In this latter case, the customer will be responsible for paying any Commission approved DASR charge.

r. The UDC will have the ability to assess a charge for accepted DASRs only if such a

fee is approved by the CPUC. This charge will be billed to the CTA unless the customer is requesting to return to UDC service where the charge will be billed to the customer.

s. Following the removal of system limitations, a customer moving to new premises

may retain or start gas direct access immediately, and in any event no later than two days after a DASR has been submitted. Due to current system limitations, a customer moving to new premises who wants to retain or start gas direct access must have the CTA submit a DASR to the UDC for the new premises no less than 10 business days before the customer’s scheduled start date at the new premises. This DASR will need a special “new customer” notation. If the DASR is received after that date or without the notation of “new customer” the customer will receive the UDC’s bundled service until the DASR is processed under the procedures set forth in Section A.2.k.

t. The UDC will not hold the CTA responsible for any customer unpaid billing charges

prior to the customer’s switch to Direct Access. Unpaid billing charges will not delay the processing of DASRs and will remain the customer’s responsibility to pay the UDC. The UDC will follow current CPUC credit rules in the event of customer non-payment, which includes the disconnection of service.

u. The initial term of service for customers participating in a core aggregation group

shall be 12-consecutive months from the customer's start date and thereafter will continue month-to-month until customer or CTA provides the UDC with notice of termination, or until customer is no longer receiving service at the meter location, or until the point that customer elects to reclassify from core to noncore status.

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RULE 32 Sheet 15



D. DELIVERY OF GAS

1. Transportation of Customer Procured Gas

CTAs participating in the Program will perform gas deliveries pursuant to the provisions and conditions set forth in Rule No. 30, Transportation of Customer Procured Gas and Rule 14, Shortage of Gas Supply, Interruption of Delivery and Priority of Service.

2. Imbalance Services

The CTA is responsible for balancing transportation services with the customer's end-use consumption. The CTA is responsible for managing the imbalances of the end-users through means which include participation in the UDC's Imbalance Trading Program pursuant to the provisions of Schedule No. G-IMB. Imbalances will be calculated on an aggregated customer basis, not by individual account or delivery point. Imbalances will be determined by comparing the amount of gas delivered to the UDC and the amount of gas actually consumed by the customers. The CTA’s DCQ will be used as a proxy for gas actually consumed by their customers. Immediately each month when actual meter usage information becomes available, an adjustment to the Utility Gas Procurement Department’s imbalance account will be made to account for any differences between actual consumption of the core customers and the Daily Forecast Quantity, company use and LUAF. The CTA shall be responsible for all imbalance charges, including any Utility Users Tax. The CTA may pool the positive and negative imbalances of its customers in order to avoid or minimize imbalance charges.

E. STORAGE RIGHTS AND OBLIGATIONS

1. Service Description

The utility shall acquire storage capacity and related services for all its core customers, including self-procurement customers. The utility, on a non-discriminatory basis, shall arrange with an agent/broker representing core aggregation customers served under Schedule GTCA, and self-procuring core customers served under Schedule GTC, the assignment of a pro-rata share of the utility's firm storage rights allocated to serve core customers.

2. Storage Injection and Withdrawal Rights

Assignment of storage rights and costs will be allocated to each CTA in the same proportion as storage costs are allocated to the customer classes represented by each CTA. Thereby, providing the core customer with a comparable level of reliability regardless of whether they take UDC fully-bundled service or Core Aggregation Transportation Service.

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San Diego Gas & Electric Company San Diego, California Canceling Original Cal. P.U.C. Sheet No. 16819-G

RULE 32 Sheet 16


16C8 Issued by Date Filed Dec 1, 2014 Advice Ltr. No. 2338-G Lee Schavrien Effective Dec 1, 2014 Senior Vice President Decision No. 14-08-043 Regulatory Affairs Resolution No.

E. STORAGE RIGHTS AND OBLIGATIONS (Continued)

1. Charges for Storage Services

The costs of storage services provided to core customers are recovered through the transportation rates paid by core customers under Schedules GTCA (Core Aggregation) and GTC (Transportation for Large Core Customers).

2. Monthly Storage Inventory Requirements

Storage capacity will be assigned to individual core customers, including self-procurement customers, on a pro-rata basis in a manner consistent with the Utility Gas Procurement Department’s minimum storage inventory requirements. This gas in storage may not be subject to any encumbrances of any kind. CTAs will not be allowed to withdraw gas below these month-end targets.

3. Adding and Deleting Customers

When CTAs add new customers, gas stored on behalf of those customers shall be automatically sold, at a rate equal to the utility's posted current month core subscription weighted average cost of gas (WACOG), to the CTA if the amount of gas stored exceeds a minimum threshold of 300,000 therms. To the extent that this automatic transfer of title does not occur, the Aggregator will remain obligated to meet all applicable storage targets set forth in this rule.

4. Secondary Market Opportunities

CTAs who hold firm storage rights in addition to those which are held to meet core reliability requirements may release all or a portion of those rights in the secondary market by utilizing Schedule No. G-SMT. UDC will have the option to recall any gas stored on behalf of its core customers, at UDC’s discretion, if, in UDC’s sole judgment, such storage is necessary to serve returning customer[s] defined in Section E.5.

F. OTHER TARIFFS

Service under this Rule is subject to the terms and conditions of UDC’s tariff schedules on file with the CPUC, including all applicable contracts and agreements.

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Attachment S: SoCalGas Rule 33, excerpt


Rule No. 33 Sheet 1 ELECTRONIC BULLETIN BOARD (EBB)


ADVICE LETTER NO. 4240 Lee Schavrien DATE FILED May 6, 2011 DECISION NO. Senior Vice President EFFECTIVE Oct 1, 2011 1C11

11-04-032 Regulatory Affairs RESOLUTION NO.

A. GENERAL

Utility will provide end-use customers, authorized marketers, and aggregators (hereinafter "User") access to its electronic transaction information and communication system known as Electronic Bulletin Board (EBB), as defined in Rule No. 1, contingent upon User meeting all conditions of Utility for authorization to use the EBB system. The general terms and conditions applicable to the provision and use of EBB are set forth herein. Utility may terminate all or any part of the EBB program at any time, but will provide as much prior notice of any such termination as reasonably possible. Use of the EBB is not mandatory. Utility reserves the right at any time to deny EBB access to any requesting party that has not completed the necessary qualification procedures, or that Utility reasonably believes is not financially or technically qualified to use the EBB.

B. EBB SERVICES

Utility has implemented the EBB to facilitate certain Utility-to-User and User-to-User interactions through the use of the Internet. The EBB is intended to be accessible for the following services or functions (hereinafter “Services”):

1. nominating with Utility for transportation or storage service on Utility's intrastate system, including

the ability for User to verify receipt and allocation by Utility of such nominations; 2. obtaining gas usage information by account or group of accounts for User with electronic gas

measurement; 3. providing imbalance quantities and serving as an interactive mechanism for offering for sale or

purchase of imbalance quantities and submitting transportation imbalance and storage trade requests to Utility for validation during the imbalance trading periods;

4. providing an interactive mechanism for submitting Backbone Transportation Service (BTS)

capacity trade requests to Utility for validation and posting of BTS secondary market transactions and approving all transactions;

5. providing an interactive mechanism for submitting storage rights trade requests to Utility for

validation and posting of BTS secondary market transactions and approving all transactions; 6. obtaining information regarding such things as Utility tariff rate changes, curtailments, regulatory

notices and other general information items;

T T T

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SOUTHERN CALIFORNIA GAS COMPANY Revised CAL. P.U.C. SHEET NO. 43389-G LOS ANGELES, CALIFORNIA CANCELING Revised CAL. P.U.C. SHEET NO. 42870-G 42310-G, 42311-G


(Continued)


ADVICE LETTER NO. 3818-A Lee Schavrien DATE FILED May 12, 2008 DECISION NO. Senior Vice President EFFECTIVE Jul 18, 2008 2C18


B. EBB SERVICES (Continued) 7. acting as an electronic mail system between User and Utility; 8. obtaining Utility operational data as required in D.98-03-073, Remedial Measures; and, 9. other electronic bidding, trading and contracting for gas transactions and information sharing in

connection with such other tariff services or programs as may be available from Utility from time to time or in connection with Utility’s pipeline systems or related services offered by Utility or third parties.

C. USER HARDWARE REQUIREMENTS

To access and use the EBB system, authorized User must have access to the Internet. EBB technical requirements are posted on the EBB website.

D. ACCESS AND RESTRICTIONS 1. Once User has satisfactorily met all of Utility's requirements for authorization to access the EBB,

including the execution of an Electronic Bulletin Board Agreement (Form 6800) and all necessary Exhibits thereto, Utility will provide such User access to and the capability to enter electronically into the EBB applications selected by User.

2. Use of the EBB shall at all times be subject to Utility’s posted EBB “Legal” and “Privacy”

policies, which may be changed by Utility without prior notice. 3. All data submitted to the EBB by User and all information related to transactions entered into by

User through the system shall be available on a non-exclusive basis by Utility, and both Utility and User shall have the right to use, for normal business operations such information subject to the confidentiality provisions in Section H.2 of this Rule.

4. User shall not modify, duplicate, revise or otherwise manipulate the EBB website, any content

posted thereon by Utility, or based on or derived therefrom, or any software programs used in connection with the EBB in any manner. Such prohibited actions shall include without limitation reverse assembling or reverse compiling, translating or converting software programs or any portion thereof to human readable form, or transferring, assigning, distributing or otherwise making available copies of software programs without the express prior written consent of Utility.

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(Continued)


ADVICE LETTER NO. 4047 Lee Schavrien DATE FILED Dec 8, 2009 DECISION NO. Senior Vice President EFFECTIVE Feb 1, 2010 3C18


D. ACCESS AND RESTRICTIONS (Continued) 5. User shall not in any way infringe upon the proprietary rights of Utility or any other party with said

rights or in any way violate the applicable laws, tariffs or regulations of any governmental entity. User's use of the EBB system and any and all software programs and documentation provided therewith is at all times subject to all applicable legal, regulatory, and tariff restrictions, including without limitation trademark and copyright laws, and User shall use the EBB in compliance with all said restrictions.

6. Utility may terminate or suspend User’s rights to access the EBB Services and to conduct some or

all transactions in accordance with the applicable Tariff Rules and contracts in the event User defaults or breaches its obligations in connection therewith. If User is delinquent in its payments to Utility for a particular type of service transaction, Utility may suspend User’s rights to enter into such transactions using the EBB until User cures the default in full.

7. At all times during the term hereof, Utility reserves the right to modify or alter the EBB access and

content, add new Services and any software and/or documentation or other materials used in connection with the EBB. Subject to any necessary approvals, all such modifications or alterations shall become subject to this Rule.

E. OPERATIONAL AND INFORMATION POSTINGS 1. Operational Postings

• Transmission Zone and Receipt Point Capacities on a cycle-by-cycle basis; • Storage capacities (injection and withdrawal) on a cycle-by-cycle basis; • Derivation of system capacities; • Estimated daily (and hourly if available) pipeline operational and scheduling information,

e.g., system sendout, off-system deliveries and scheduled quantities at all receipt points*; • Actual daily (and hourly if available) pipeline operational and scheduling information, e.g.,

system sendout, off-system deliveries and scheduled quantities at all receipt points; • Estimated daily storage operational and scheduling information, e.g., injection capacity

and scheduled injections, withdrawal capacity and scheduled withdrawals*; • Actual daily storage operational and scheduling information, e.g., injection capacity and

scheduled injections, withdrawal capacity and scheduled withdrawals; • Daily total physical storage inventory levels**; • Weekly physical core storage inventory levels; • Daily operational information depicted in graphical form to show storage inventory levels; • Status of system balancing rules (daily, winter, monthly);

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(Continued)


ADVICE LETTER NO. 4240 Lee Schavrien DATE FILED May 6, 2011 DECISION NO. Senior Vice President EFFECTIVE Jun 5, 2011 4C10


E. OPERATIONAL AND INFORMATION POSTINGS (Continued) 1. Operational Postings (Continued)

• OFO status*; • Composite weighted average temperature*; • Transmission fuel use*; • Storage injections and withdrawals for customer balancing*; • Total daily customer imbalance*; and • Unsubscribed unbundled firm storage injection and withdrawal capacity*.

* This information posted on the current day and next three-day forecast basis with the forecasted

information being updated for each nomination cycle. ** This information posted on the current-day and next three-day forecast basis.

2. G-PAL Postings

• Weekly net G-PAL position, weekly G-PAL volumes loaned, and weekly G-PAL volumes parked by its Operations Hub.

• Withdrawal schedules for all G-PAL volumes parked and repayment schedules for all G-PAL volumes loaned.

• Any Operations Park and Loan Services transactions with Sempra affiliates or the Utility Gas Procurement Department, if discounted below the maximum tariff rate, will be posted consistent with the Utility’s rules governing the posting of discounted transportation services for affiliates but no later than the next business day on the Utility’s Electronic Bulletin Board (EBB).

3. Contractual Maintenance and Regulatory Postings

• An index of firm rights holders for backbone transportation and storage contracts; • Planned and actual service pipeline and storage outages through its Maintenance

Schedules; • Terms and conditions regarding secondary market transactions; • Customers posted information for the marketplace; • Tariffs and other regulatory filing information; and • Affiliate transaction information.

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SOUTHERN CALIFORNIA GAS COMPANY Original CAL. P.U.C. SHEET NO. 45394-G LOS ANGELES, CALIFORNIA CANCELING CAL. P.U.C. SHEET NO.


(Continued)




E. OPERATIONAL AND INFORMATION POSTINGS (Continued) 4. Rule 41 Postings

• All requests for supplies by the Gas Control Department to the Operational Hub shall be posted on the Utility’s EBB no later than 72 hours after the minimum flow event in order to avoid an increase in the cost of such services that may result from posting this information contemporaneously.

• In the case of the Operational Hub communicating with the Utility Gas Procurement Department as provider of last resort to maintain the Southern System flow requirement, the Utility will post the terms of any resulting transaction within 72 hours after the conclusion of the transaction. The Utility will post the following information about any such transaction: price, volume, date, delivery/receipt points and any special terms.

• Beginning in 2010, the Utility shall post an annual report (Report) of system reliability issues on its website at least two weeks prior to each annual Utility Customer Forum.

5. G-TBS Postings

• The Utility will post all G-TBS storage transactions on its EBB within one business day of execution, including the counterparty name, quantity of storage services contracted on an unbundled basis, contract prices, and contract term.

• The Utility shall post on its EBB as soon as practicable prior to each nomination cycle the injection and withdrawal capacity of its storage system. The Utility shall post on its EBB the aggregate scheduled injection and withdrawal amounts for the completed gas flow day.

6. G-SMT Postings

• The Utility will file quarterly reports to the Commission stating the storage capacity rights held by Customers. Such reports will provide the name of the entity holding firm storage rights, the volume held, usage of the rights, and the terms of those rights, including pricing. Such information, excluding usage, will also be posted on the Utility’s EBB and will be updated daily;

• The Utility will post on its EBB all contracted firm storage capacity and the available unsubscribed storage capacity for sale. This information will be updated on a daily basis.

• The Utility will post on its EBB a summary of the completed secondary market transactions, listing releasing party, acquiring party, amount of capacity, transaction price, and term of the release. Information regarding secondary market transactions will be posted the next business day.

• Market participants can voluntarily post secondary market transaction offers on the Utility’s EBB.

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Rule No. 33 Sheet 6 T ELECTRONIC BULLETIN BOARD (EBB)

(Continued)




F. AUTHORIZED INDIVIDUAL USERS

Authorized User shall allow only its specifically authorized employees and/or agents access to and use of EBB and all Software Programs and Software Documentation. Authorized User shall identify each and every such individual to Utility in writing, through the use of the Exhibit A EBB Logon ID Request Form, (Form 6800-A), prior to their use of the EBB system. Authorization is limited strictly to such designated individuals until such time as User requests otherwise. In the event such individual's authorization to use system is terminated for whatever reason, including but not limited to a change in employment and/or the necessity to change authorization to another person or persons, authorized User must provide Utility immediate notice thereof and must request any new authorizations required as a consequence. User shall be solely responsible for the actions of any individuals it designates in connection with the EBB system. If User desires to change or add a type of EBB Service or to change the individuals authorized on its behalf to conduct electronic transactions, User shall fax to Utility a new Logon ID Request Form. Such authorized representative shall be the individual named in a Delegation of Authority Form (Exhibit B to Form 6800) or the sole proprietor, or an authorized officer or partner with authority to bind User. The changes or additions shall be effective as soon as reasonably possible after Utility receives the new Log On ID Request Form, and in any event, not later than the close of Utility’s business day if the fax is received at least one hour prior to closing and shall be effective within the first hour of the next business day if received thereafter. Utility may, but is not required to, send written confirmation to User of Utility’s receipt of the changes or additions. To revoke the authority of an individual to enter into electronic transactions on behalf of User, User may e-mail Utility with such revocation, which shall be effective upon User’s receipt of an e-mail confirmation from Utility.

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(Continued)




G. ELECTRONIC TRANSACTIONS

1. By using the EBB, User agrees to enter into and obtain the Services electronically and agrees to all terms and conditions of this Rule and other applicable Tariff Rules and Schedules and applicable contracts. User will be bound by all the applicable terms and conditions of Utility’s Tariff Schedules and Rules as in effect from time to time, including the Electronic Bulletin Board Agreement and all Exhibits thereto, which are made available by Utility and selected by User for electronic transactions. User is responsible for any and all costs or expenses associated with its accessing and utilizing the EBB.

2. The Services to be transacted through the EBB and designation of the individuals authorized by User to perform those applications shall be as set forth in the Electronic Bulletin Board Agreement Exhibit A, EBB Logon ID Request Form (Form 6800-A).

3. Any Services or actions taken through the use of a User’s Logon ID, regardless of the person

initiating such action using User’s Logon ID, will be binding on User and all transactions entered into with the User’s Logon ID will be legally binding on User in accordance with the Tariff Rules, Schedules and any contract applicable to such transaction, whether or not such applications including transactions or actions were, in fact, authorized by User.

4. All Services which are transactions entered into through the EBB shall be deemed to be “in writing” and to have been “signed” for all purposes and that any record of any such transaction will be deemed to be “in writing”. Utility and User will not contest the legally binding nature, validity or enforceability of any transaction executed through the EBB based on the fact that it was entered into and executed electronically, and expressly waive any and all rights either may have to assert any such claim. Accordingly, an electronic signature by a party transmitted to the other party may be relied upon, and is enforceable for all purposes in connection herewith and no manual signature shall be required in lieu thereof. However, additional terms or conditions proposed by User in any transmission involving Utility’s services shall be deemed rejected unless accepted by Utility in writing.

5. Customer shall indemnify and hold harmless Utility from and against any actions, claims,

liabilities, damages, costs and expenses (including reasonable attorneys’ fees and disbursements) arising in connection with its utilization of Utility’s EBB or the licensed materials or resulting from or arising out of any act or omission by any person obtaining access to the EBB through User’s Logon ID; provided, however, Utility shall be responsible and indemnify and hold harmless User from and against any actions, claims, liabilities, damages, costs and expenses (including reasonable attorneys’ fees and disbursements) related to Utility's ownership of the EBB and the licensed materials.

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(Continued)




H. UTILITY REPRESENTATION

1. Utility's provision of access to the EBB and any and all use thereof is strictly on an informational basis only.

2. Utility does not represent or warrant that the EBB will meet authorized User's requirements or that

their operation will be uninterrupted or error-free, and specifically disclaims any representation of fitness for any particular purpose or use.

3. Utility's provision of access to the EBB and its maintenance thereof shall in no way be construed as

to imply or provide any warranty, sponsorship, or approval by Utility as to the efficacy of the EBB nor of any of the arrangements or relationships made by or based on the use of the EBB by authorized User or any representatives acting on User's behalf.

4. Utility expressly disclaims any warranty, representation or opinion, whether expressed or implied,

as to the legal enforceability of any relationship which authorized User may enter into associated in any way with information obtained from the EBB.

5. The establishment, maintenance or termination of any commercial or legal relationship(s) between

authorized User and any other party or parties ("Third Parties") based in whole or in part on information obtained from the EBB are the sole responsibility of the authorized User and such Third Parties.

6. Authorized User shall indemnify, hold harmless and defend Utility, its officers, agents and

employees, from and against any and all loss, damage, expense, cost (including reasonable attorneys’ fees, costs and disbursements) and/or liability arising out of or in any way connected with the performance or non-performance of the EBB, however caused, except to the extent caused by active negligence or willful misconduct of Utility, its officers, agents and employees.

7. User is solely responsible for the selection of Services, particular transactions and products to

achieve User’s intended results. Utility disclaims any warranty, and makes no opinion, express or implied, as to the advisability or enforceability of any arrangement or relationship User may enter into with any third party based upon the EBB or information obtained from or through the EBB, or the suitability or fitness of such third party. Utility also disclaims any responsibility for any loss or injury attributable in whole or in part to its actions or inactions in connection with the EBB (but any separate contract entered into by Utility and User through the EBB shall be governed by the terms thereof). Such disclaimer by Utility includes without limitation any actions or inactions of Utility related to the design and operation of the EBB, User utilization of the EBB for any purpose or any error or malfunction related thereto, including its availability at times desired by User.

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SOUTHERN CALIFORNIA GAS COMPANY Original CAL. P.U.C. SHEET NO. 45398-G LOS ANGELES, CALIFORNIA CANCELING Original CAL. P.U.C. SHEET NO. 43394-G


(Continued)




H. UTILITY REPRESENTATION (Continued)

6. If any transmission/communication is received in an unintelligible, electronically unreadable, or garbled form, the receiving party shall promptly notify the originating party (if identifiable from the received transmission) in a reasonable manner. The sending party shall make reasonable efforts to promptly transmit a corrected, non-garbled communication in lieu of the original message.

7. In the event of a dispute, Utility’s electronic records (or a “hard copy” downloaded therefrom) are

conclusive evidence of any transaction or data applicable thereto. I. GENERAL CONDITIONS

1. Access to and utilization of the EBB by User may be monitored by Utility for purposes of

monitoring levels of activity in categories of transactions, for purposes of maintaining the functional and operational integrity of the EBB and for purposes of determining compliance with applicable laws and regulations.

2. The information obtained by Utility from monitoring the transactions of Users shall remain

confidential and shall not be disclosed by Utility to third parties except as may be required to comply with regulatory reporting requirements or otherwise required by law. Information submitted by a User regarding bids, offers, or transactions may be displayed by Utility on the EBB provided such displays will not identify User by any identifying information prohibited by the Commission.

3. In no event will Utility or User be liable for any special, indirect, incidental, punitive, or

consequential damages in connection herewith as provided in Rule No. 04, even if one party has advised the other of the possibility of such damages.

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Attachment T: Aliso Canyon Mitigation Measures Impact Report,

May 2018 Update, excerpts

STATE OF CALIFORNIA Edmund G. Brown Jr., Governor

PUBLIC UTILITIES COMMISSION

505 VAN NESS AVENUE

SAN FRANCISCO, CA 94102-3298

Aliso Canyon Mitigation Measures

Impact Report (May 2018 Update)

Executive Summary A major gas leak was discovered at the Southern California Gas Company’s (SoCalGas) Aliso Canyon natural gas storage facility (Aliso Canyon) on October 23, 2015. On January 6, 2016, the governor ordered SoCalGas to maximize withdrawals from Aliso Canyon to reduce the pressure in the facility. The California Public Utilities Commission (CPUC/Commission) subsequently required SoCalGas to leave 15 Billion cubic feet (Bcf) of working gas in the facility that could be withdrawn in an emergency. On May 10, 2016, Senate Bill (SB) 380 was approved, prohibiting the reinjection of gas into the facility until a comprehensive safety review was completed. On July 19, 2017, the Division of Oil, Gas, and Geothermal Resources (DOGGR) certified, and the Commission concurred, that the required inspections and safety improvements had been completed and injections could resume at Aliso Canyon. DOGGR authorized Aliso Canyon to operate at pressures up to 2,926 pounds per square inch absolute (psia), which translates into an inventory of 68.6 Bcf.1 The current maximum Aliso inventory is lower than the DOGGR-authorized amount due to another provision of SB 380, which added Section 715 to the Public Utilities Code. Section 715 requires the CPUC to determine “the range of working gas necessary to ensure safety and reliability for the region and just and reasonable rates in California.” The CPUC released a series of “715 Reports” in response to changing conditions on the SoCalGas system. The most recent report, issued on November 30, 2017, set a cap of 24.6 Bcf on Aliso Canyon inventory.2

1 Based on information provided to the CPUC by DOGGR on April 19, 2018. 2 Aliso Canyon Working Gas Inventory, Production Capacity, Injection Capacity, and Well Availability for Reliability: Supplemental Report for Winter 2017-18 (715 Report): http://www.cpuc.ca.gov/uploadedFiles/CPUC_Public_Website/Content/News_Room/News_and_Updates/Draft%20Update%20to%20Aliso%20Canyon%20Working%20Gas%20Inventory%20-%20715%20Report%20-%20113017.pdf.

Page 1

http://www.cpuc.ca.gov/uploadedFiles/CPUC_Public_Website/Content/News_Room/News_and_Updates/Draft%20Update%20to%20Aliso%20Canyon%20Working%20Gas%20Inventory%20-%20715%20Report%20-%20113017.pdf

http://www.cpuc.ca.gov/uploadedFiles/CPUC_Public_Website/Content/News_Room/News_and_Updates/Draft%20Update%20to%20Aliso%20Canyon%20Working%20Gas%20Inventory%20-%20715%20Report%20-%20113017.pdf

2

Gas storage is used to meet peak daily and seasonal gas demand and to hedge against price volatility in natural gas commodity markets. Storage can also help compensate for maintenance activities on the gas system’s pipelines. This feature has become more salient due to the rupture of Line 235-2 on October 1, 2017, the ongoing maintenance on Lines 3000 and 4000, and the expiration of a right-of-way on Line 2000. SoCalGas has released no estimate of when these pipeline outages will be resolved, with the exception of Line 3000, which is expected to return to service on September 17, 2018. The reduced availability of Aliso Canyon combined with significant, ongoing pipeline outages on the SoCalGas system continue to threaten gas and electric reliability in Southern California. In response to the Aliso gas leak and resulting restricted use of the storage facility, the CPUC enacted, and continues to implement, a series of policies to increase reliability by reducing demand for natural gas. This report provides an update of the mitigation measures the CPUC has undertaken and the impacts of these efforts on summer and winter gas peak demand. Because it is difficult to determine whether and to what extent electricity reductions would translate directly into gas transmission reductions in the Aliso-impacted area (as opposed to gas reductions on the system as a whole), to be conservative, this report does not assume that electricity reductions in the winter result in gas reductions in the Aliso-impacted area. During peak summer days, the report assumes that electricity reductions in all of Southern California Edison’s (SCE’s) territory except Big Creek/Ventura and all of San Diego Gas & Electric’s (SDG&E’s) territory reduce gas demand. Estimates of the impact on gas demand resulting from electricity reductions on peak summer days use heat rates of the marginal electric generation facilities, including a 10% line loss.3 Additional resource-specific simplifying assumptions are described throughout the document.

In addition to estimating the impacts of our Aliso-related efforts, this report also provides information on resources that have been added to Aliso-impacted areas since 2010 that reduce summer and winter gas demand, as well as future resources that have been authorized and are anticipated to be procured within the next five years. The purpose of this additional information is to provide a better understanding of the wide breadth of customer-facing resources already installed or planned to reduce reliance on natural gas, which in turn impacts the number of additional opportunities that exist to achieve further reductions.4

3 These assumptions result in a conversion factor of 12 MMbtu/MWh. MMbtu are in turn converted to MMcf by dividing MMbtu by 103. 4 Note that this report focuses on demand-side reductions. Significant additional efforts to reduce California’s reliance on fossil fuels are also being implemented on the supply side — most notably the increasingly aggressive renewable goals that are dramatically reducing demand for natural gas in the state.

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In fact, some resources whose installation dates were accelerated in response to the Aliso leak can no longer be considered “Additional Aliso-Related Resources” since they would have come on line by now absent the Aliso-related acceleration. Consequently, some of the impacts identified in the “Additional Aliso-Related Resources” category in previous reports are now included in the “Existing/Previously Planned Resources” category. Also, because many of the significant Aliso mitigation measures are now in place, they are embedded in updated peak demand assessments. Given these factors, one significant change from past reports is that this Executive Summary does not include a table that summarizes Aliso-specific mitigation measure impacts and a calculation of the portion of peak demand being met by mitigation efforts. Instead, Table 1 summarizes estimated peak day gas demand reductions resulting from mitigation measures since 2010, and Table 2 summarizes estimated impacts of proposed or anticipated future mitigation resources that may come on line over the next five years.

Table 1: Estimated Peak Day Gas Demand Reductions Resulting from Mitigation

Measures since 2010 (MMcf)

Mitigation Measures Summer Winter

Gas Balancing Rules 536.5 72.3 Energy Efficiency 263.3 77.3 Energy Savings Assistance Program 6.8 2.5 California Solar Initiative: Thermal Program 0.9 0.9 Customer-Side Solar PV Electricity Generation 72.4 0 Marketing Education and Outreach5 NA NA Electricity Storage 8 0 Electric Demand Response 63 0 Gas Demand Response6 NA NA Total 950.8 153

5 ME&O programs encourage customers to take immediate reduction actions and to adopt demand-side measures that result in savings identified in other sections of this report. Because of this, as well as the wide disparity of reported savings from CAISO and those found by Opinion Dynamics and the fact that it is uncertain which ME&O programs will be authorized in 2018, the CPUC is not estimating direct savings from these programs in this report. 6 As the “first of its kind” gas demand response program developed specifically as an Aliso mitigation measure, only the gas impact field of the “Additional Aliso-Related Resource” row of the savings estimate table is relevant for this resource, and as noted in the text, evaluation results for the 2017-18 winter season Gas Demand Response program are expected in summer 2018. Consequently, the summary table is not applicable to this resource.

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For comparison purposes, these gas demand reductions represent approximately 27% of the current estimated summer peak day gas demand of 3,500 MMcf and approximately 3% of winter peak day gas demand of 4,955 MMcf.7

Table 2: Proposed/Anticipated Future Aliso Canyon

Mitigation Measure Peak Day Impacts (MMcf)


Gas Balancing Rules 0 20.9 Energy Efficiency 279.2 140 Energy Savings Assistance Program 3 1.4 Customer-Side Solar PV Electricity Generation 61 NA Marketing Education and Outreach NA NA Electricity Storage 21.1 NA Electric Demand Response 62.9 NA Gas Demand Response NA NA Total 427.2 162.3

Again, for comparison purposes, these gas demand reductions represent approximately 12% of the current estimated summer peak day gas demand of 3,500 MMcf and approximately 3% of winter peak day gas demand of 4,955 MMcf. Finally, it is important to note that this report only looks at the impacts of mitigation measures ordered by the Commission and/or implemented by entities overseen by the Commission. It does not look at the success of mitigation measures adopted by the publicly owned electric utilities such as the Los Angeles Department of Water and Power (LADWP) except in limited instances in which SoCalGas partnered with LADWP on combined electric and gas reduction efforts, nor does the report review the ability of these entities to implement mitigation measures similar to some of the successful measures outlined in it.

7 Again, since these measures are now in place, they are embedded in peak demand assessments. Representing them as percentages of peak demand are provided for comparative purposes and should not be interpreted as opportunities in additional reductions in gas demand. Rather, these estimates reflect the amount of additional peak gas demand that would have existed absent these programs and efforts.

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I. Gas Balancing Rules

Estimated Peak Day Reductions (Therms)

Summer Winter

Existing/Previously Planned Resources Online by 2018 5,364,504 723,500 Additional Aliso-Specific Resources Online by 2018 0 0 Authorized/Anticipated Future Resources 0 209,000

Background

Gas balancing is the need for gas supply to match gas demand. For natural gas pipeline systems to remain physically “in balance,” they must operate within a set range of pressures. If there is not enough gas in the system, the pressure falls and gas does not flow properly. If there is too much gas, the pressure rises, posing a risk to the structural integrity of the pipelines. SoCalGas is responsible for maintaining the system’s balance, but it does not control all gas procurement. A division of the utility known as the Gas Acquisition Department purchases gas for most of the residential and small business customers known as core customers.89 The remainder of the gas is procured by ‘noncore customers.’ – large gas users such as electric generation plants, refineries, and some manufacturers. Noncore customers purchase their own gas and pay the utility to transport it to their facilities. Historically, customers only had to balance their gas deliveries to within 10% of their gas usage by the end of the month. In the winter, additional balancing rules applied, but they were relatively lax, in most cases requiring customers to supply at least 50% of their burn over a five-day period. SoCalGas was able to support these flexible balancing requirements due to its ample gas storage facilities, which allowed the utility to quickly withdraw gas to remedy a shortage or inject gas to reduce a surplus. Even before the Aliso Canyon gas leak, SoCalGas initiated several policies to reduce customers’ daily imbalances. In the aftermath of the leak, the CPUC further tightened those new policies through the Summer and Winter Balancing Settlement Agreements.10

8 The Gas Acquisition Department is not allowed to communicate with the SoCalGas System Operator and only has access to the same publicly available system information that noncore customers use. 9 Some core customers are supplied by core wholesale customers or core transport agencies. 10 The Summer Settlement Agreement (D.16-06-021) became effective June 1, 2016, and expired November 30, 2016. The Winter Settlement Agreement (D.16-12-015) went into effect December 1, 2016. It was initially set to

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Tighter balancing rules do not result in less natural gas usage. They do, however, reduce the need for storage by lessening the utility’s need to inject and withdraw gas to balance the system.

Existing or Previously Planned Resources Online by 2018

A. Implementing Low Operational Flow Order Procedures: The CPUC approved Low Operational Flow Order (OFO) procedures on June 16, 2015, which went into effect on December 3, 2015.11 Under these rules, a Low OFO is triggered when there is not enough gas forecasted to be coming into the system to meet demand. The Low OFO procedures allow SoCalGas to require customers to deliver up to 95% of their daily gas usage and to impose increasingly severe financial penalties for noncompliance.

B. Reducing the Monthly Balancing Requirement: The monthly balancing requirement was reduced from 10% to 8% in a non-Aliso-related decision that went into effect on September 1, 2016.12

Additional Aliso-Related Resources Online by 2018

A. Implementing the Summer and Winter Balancing Settlement Agreements: On June 1, 2016, a settlement agreement went into effect that temporarily reduced the High OFO band of permissible overdeliveries from 110% to 105% of a customer’s actual burn13 and acknowledged that SoCalGas’ existing rules allow the utility 1) to call simultaneous High and Low OFOs and 2) to set the OFO trigger, i.e. the amount of allowable gas imbalance, based on operational conditions rather than using a constant number. In practice, the latter provision allowed SoCalGas to reduce the trigger from .348 Bcf to as low as .137 Bcf depending on conditions. The Winter Balancing Settlement Agreement extended these terms, which are now set to expire on November 30, 2018. Results Tightening the gas balancing rules has had a profound effect on the SoCalGas system. Customers have changed their behavior, more closely matching their gas deliveries with their burn even on days when no Operational Flow Orders are called. Customers have also improved their balancing on high sendout days, as can be seen in the analysis below. It

expire on March 31, 2017, but the deadline has been repeatedly extended. It is currently set to expire on November 30, 2018. 11 Decision (D.) 15-06-004 and Resolution G-3511, respectively. 12 D.16-06-039. 13 High OFOs are the inverse of Low OFOs. Customers are subject to penalties if they bring in more than 105% of their actual (noncore) or forecast (core) gas burn.

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should be noted that disaggregating the incremental impacts of each individual policy is beyond the scope of this report. Since the policies build on each other, only their combined impact is analyzed. This year, compared to the 2017 report, changes were made to calculating the impact of tighter gas balancing rules. First, the threshold for a winter high sendout day was reduced from 4 Bcf to 3.5 Bcf. This is due to the fact that there were no days during winter 2017-2018 when sendout was at least 4 Bcf. The threshold for a summer high sendout day remained unchanged at 3.2 Bcf. Second, instead of using data from only one year, a five year average of highout days was used to compare the impact of changing the balancing rules. Both of these changes increased the number of data points available, making the results more robust.14 For comparison, this year’s report looked at 180 winter days and 62 summer days, while the 2017 report only examined 11 winter days and 20 summer days. Last, when providing the relevant data, SoCalGas counted the gas used by Core Transport Agents in the noncore rather than the core category, causing core totals to change compared to last year.

Table 3: Number of High Sendout Days Per Season

Winter Summer

Year High Sendout Days Year High Sendout Days 2010-11 36 2011 1 2011-12 30 2012 15 2012-13 40 2013 12 2013-14 16 2014 4 2014-15 12 2015 14 2015-16 22 2016 6 2016-17 18 2017 10 2017-18 6 Total 180 62

Despite the expanded dataset used this year, the available data on post-Aliso high sendout days remains limited to only three winter seasons and two summer seasons since the October 2015 Aliso Canyon gas leak and the December 2015 institution of the new Low OFO rules. In addition, since the winter of 2015-16 was highly atypical, data from that season was not

14 In the 2017 report, only data for winters 2014-15, 2015-16, and 2016-17 were examined. Only four days met the 4 Bcf high sendout threshold in 2014-15 and 2015-16 and three in 2016-17. For summer, a comparison between the summers of 2015 and 2016 was used. There were 14 high sendout days in summer 2015 and six in 2016.

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8

included in the averages cited below. 15 Between December 2015 and January 2016 To reduce pressure in the field, Aliso Canyon was on emergency withdrawal between December 2015 to January 2016. The large amounts of gas withdrawn changed the normal supply dynamics during the coldest months of the year, resulting in only three Low OFOs being called out of the 22 high sendout days that winter. Results are presented separately for summer and winter because the characteristics of gas usage vary significantly by season. In the summer, noncore customers account for roughly 79% of total high sendout day demand; in the winter, they account for about 44% of high sendout day demand. Summer

Average combined core and noncore deliveries changed from 12% less than scheduled burn in the summers 2011-15 to 4% more than burn on high sendout days in 2016-17 when a Low OFO was called. This change is equivalent to an average reduction in the need to withdraw gas from storage of 5.36 million therms. This shift was driven in part by a change in behavior by the core, which went from underdelivering by an average of 28% on 2011-15 peak days to overdelivering by 8% on high sendout/Low OFO days in 2016-17.The noncore also improved significantly, going from average peak day underdeliveries of 6% in 2011-15 to overdeliveries of 5% in 2016-17.

Table 4: Average Imbalances on Summer High Sendout Days16

Year Core +

Noncore Core Noncore 2011-2015 -12% -28% -6%

2016 6% 8% 7% 2017 3% 9% 2%

The new gas rules also reduced the volatility of deliveries. On high sendout days in summers 2011-15, combined core and noncore deliveries ranged from a low of -28% to a high of 2%. Deliveries on high sendout/Low OFO days in summer 2016-17 ranged from -1% to 14%.

Winter

15 Averages are used because all disaggregated daily information for core and noncore customers was deemed confidential by SoCalGas. 16 For summers 2016-17, only high sendout days when a Low OFO was called are included.

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9

Under the new rules, average combined core and noncore underdeliveries decreased from 5% for the winters 2010-11 through 2014-15 to 4% on high sendout/Low OFO days during the winters 2016-17 through 2017-18.17 This change equates to an average reduction in the need to withdraw gas from storage of 723,500 therms on winter high sendout days.

Table 5: Average Imbalances on Winter High Sendout Days18

Year(s) Core

+ Noncore Core Noncore 2010-11 to 2014-15 -5% -6% -4% 2015-16 7% 0% 23% 2016-17 -4% -8% 6% 2017-18 -3% -3% 7%

Tighter balancing rules also greatly reduced volatility in customer deliveries: core and noncore customers combined swung between 45% overdeliveries and 45% underdeliveries in the five winters before the Low OFO rules were introduced. In the winters 2016-17 and 2017-18, imbalances on high sendout/Low OFO days ranged from 11% underdeliveries to 6% overdeliveries.

Authorize/Anticipated Future Resources

A. Changing Core Balancing Rules: The Winter 2016 Action Plan identified several mitigation measures intended to help compensate for the unavailability of Aliso Canyon. Among them was a measure to change balancing rules for core customers. Currently, on OFO days, core customers served by the utility19 have to balance to a forecast of the day’s gas use rather than to actual use. This means that on a Low OFO day, these core customers do not incur financial penalties as long as they bring in 95% of their forecasted burn. There is no penalty for the forecast being wrong. Noncore customers, in contrast, must balance to their actual use.

As part of the Winter Balancing Settlement Agreement, SoCalGas filed Application (A.) 17-10-002 on September 30, 2017, addressing the feasibility of incorporating Advanced Metering Infrastructure data into the core balancing process. The Scoping Memo issued on April 25, 2017,20 found that the issue of the core balancing to actuals was within the scope of

17 Winter 2015-16 data is not included in this comparison due to the emergency withdrawals at Aliso Canyon. 18 For winters 2015-16 through 2017-18, only high sendout days when a Low OFO was called are included. 19 Core wholesale customers and core transport agents have to balance to actual, not forecasted, burn. 20 A.17-10-002 Scoping Memo: http://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M213/K120/213120542.PDF.

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http://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M213/K120/213120542.PDF

10

the proceeding. This means that the proceeding could have the outcome of changing the current core balancing rules.

If the core is required to balance to actuals, there would likely be little change to summer deliveries, since the core is already overdelivering on average on high sendout/Low OFO summer days. However, over the past two winters, the core has underdelivered by an average of 6% on high sendout/Low OFO days. While significantly more consistent than in the era of loose balancing rules, the core’s deliveries remain more volatile than the noncore deliveries noncore customers have never underdelivered on a high sendout/Low OFO winter day since the new rules were put in place. If the core was required to balance to actuals, underdeliveries would likely decrease at least enough to meet the -5% imbalance tolerance. This change, from -6% to -5% average underdeliveries would result in a reduction in storage withdrawals of about 209,000 therms. If the core reduced average imbalances to zero, the savings would be roughly 1.25 million therms on a high sendout/Low OFO day.

B. Refinement of High OFO Rules: In a 2016 decision,21 the CPUC conditionally approved permanent High OFO rules that allow the utility to call a High OFO that reduces the permitted band of overdeliveries to up to 105% of burn. These permanent rules, which will go into effect once the Aliso Canyon Turbine Replacement Project (ACTR) is in service, provide for different levels of penalties ranging from $.025 per therm up to $2.50 per therm plus the daily balancing standby rate. Currently, there is a single penalty: the buyback rate. The ACTR was originally anticipated to go online by January 1, 2017. However, the Aliso Canyon leak and its aftermath cause the project to be delayed, and SoCalGas has temporarily suspended injection at Aliso Canyon. Once injection resumes, the ACTR is likely to go into service, causing the new High OFO rules to go into effect. Since the Daily Balancing Settlement Agreements already reduced the overdelivery band to 105%, Energy Division (ED) staff does not anticipate that the permanent rules will lead to a large change in delivery patterns. However, the more nuanced and potentially steeper High OFO penalties available to SoCalGas under the permanent High OFO rules may create more financial incentives for customers to match deliveries to burn on High OFO days.

21 D.16-06-039 in proceeding A.14.12-017, the Phase 1 Triennial Cost Allocation Proceeding.

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Attachment U: Catherine E. Yap Workpapers

Wintertime High OFOs

OFO dates_Date % Difference System Sendout Shows core forecast errors in % difference column OFO dates_Date % Difference

12-Feb-16 8.31% 2397000 18-Nov-17 -14.50%

13-Feb-16 -0.27% 2322000 01-Mar-17 -13.80%

19-Feb-16 17.99% 2592000 08-Mar-17 -13.40%

20-Feb-16 8.91% 2433000 09-Dec-17 -12.00%

27-Feb-16 7.41% 2123000 14-Nov-17 -9.10%

01-Nov-16 17.46% 2389000 19-Nov-16 -8.90%

02-Nov-16 4.32% 2549000 91 4.67% average all winter deviations 19-Nov-17 -8.30%

04-Nov-16 15.14% 2326000 25 27.47% -5.74% average all negative winter deviations 28-Nov-17 -8.30%

05-Nov-16 11.17% 2184000 66 72.53% 8.62% average all positive winter deviations 15-Nov-17 -7.10%

06-Nov-16 7.16% 2156000 23 25.3% 15.68% average winter deviations > 10% 11-Mar-18 -5.80%

08-Nov-16 11.15% 2504000 21-Nov-17 -5.40%

09-Nov-16 18.41% 2588000 28-Mar-17 -5.00%

10-Nov-16 26.53% 2460000 18-Nov-16 -4.87%

11-Nov-16 18.16% 2380000 16-Mar-16 -4.39%

12-Nov-16 14.60% 2153000 26-Nov-17 -4.30%

15-Nov-16 10.41% 2487000 31-Mar-18 -4.00%

16-Nov-16 4.45% 2707000 05-Feb-17 -3.50%

17-Nov-16 3.47% 2862000 26-Mar-16 -3.38%

18-Nov-16 -4.87% 2745000 22-Dec-16 -2.40%

19-Nov-16 -8.90% 2540000 22-Nov-17 -1.40%

22-Nov-16 1.42% 2735000 13-Jan-18 -1.20%

13-Dec-16 8.10% 2990000 29-Mar-17 -0.90%

22-Dec-16 -2.40% 3177000 11-Nov-17 -0.80%

05-Feb-17 -3.50% 2961000 05-Mar-16 -0.60%

08-Feb-17 0.40% 2705000 13-Feb-16 -0.27%

09-Feb-17 5.90% 2697000 19-Mar-16 0.12%

14-Feb-17 2.90% 2778000 12-Mar-16 0.14%

15-Feb-17 3.20% 2765000 08-Feb-17 0.40%

20-Feb-17 1.50% 3043000 16-Nov-17 0.70%

01-Nov-17 6.70% 2345000 27-Mar-16 0.78%

02-Nov-17 11.30% 2404000 25-Nov-17 1.00%

03-Nov-17 15.60% 2318000 25-Dec-17 1.10%

04-Nov-17 7.60% 2146000 22-Nov-16 1.42%

05-Nov-17 1.50% 2194000 20-Feb-17 1.50%

10-Nov-17 3.50% 2254000 05-Nov-17 1.50%

Att U CEYap Workpaperswinter High OFO Page 1

11-Nov-17 -0.80% 2232000 17-Nov-17 2.60%

14-Nov-17 -9.10% 2323000 14-Feb-17 2.90%

15-Nov-17 -7.10% 2311000 04-Mar-16 2.96%

16-Nov-17 0.70% 2280000 02-Dec-17 3.00%

17-Nov-17 2.60% 2243000 15-Jan-18 3.10%

18-Nov-17 -14.50% 2263000 17-Mar-16 3.15%

19-Nov-17 -8.30% 2283000 15-Feb-17 3.20%

21-Nov-17 -5.40% 2365000 17-Nov-16 3.47%

22-Nov-17 -1.40% 2317000 10-Nov-17 3.50%

24-Nov-17 9.30% 1983000 16-Dec-17 3.70%

25-Nov-17 1.00% 1983000 02-Nov-16 4.32%

26-Nov-17 -4.30% 2093000 16-Nov-16 4.45%

28-Nov-17 -8.30% 2625000 11-Mar-17 4.90%

01-Dec-17 8.00% 2486000 31-Mar-17 5.40%

02-Dec-17 3.00% 2329000 09-Feb-17 5.90%

09-Dec-17 -12.00% 2374000 30-Mar-17 6.00%

16-Dec-17 3.70% 2560000 14-Jan-18 6.50%

25-Dec-17 1.10% 2640000 26-Mar-17 6.60%

06-Jan-18 17.40% 2243000 01-Nov-17 6.70%

12-Jan-18 7.60% 2622000 06-Nov-16 7.16%

13-Jan-18 -1.20% 2309000 27-Feb-16 7.41%

14-Jan-18 6.50% 2354000 04-Nov-17 7.60%

15-Jan-18 3.10% 2729000 12-Jan-18 7.60%

30-Jan-18 8.50% 2589000 01-Dec-17 8.00%

10-Feb-18 18.60% 2426000 13-Dec-16 8.10%

12-Feb-16 8.31%

30-Jan-18 8.50%

19-Feb-16 17.99% 2397000 19-Mar-17 8.60%

01-Nov-16 17.46% 2389000 10-Mar-17 8.70%

04-Nov-16 15.14% 2326000 20-Feb-16 8.91%

05-Nov-16 11.17% 2184000 23-Mar-17 9.20%

08-Nov-16 11.15% 2504000 24-Nov-17 9.30%

09-Nov-16 18.41% 2588000 12-Mar-17 9.90%

10-Nov-16 26.53% 2460000 17-Mar-17 10.10%

11-Nov-16 18.16% 2380000 15-Nov-16 10.41%

12-Nov-16 14.60% 2153000 08-Nov-16 11.15%

15-Nov-16 10.41% 2487000 05-Nov-16 11.17%


14-Mar-17 17.10% 2526000 02-Nov-17 11.30%

15-Mar-17 19.80% 2494000 25-Mar-17 11.90%

16-Mar-17 16.30% 2462000 18-Mar-17 12.40%

17-Mar-17 10.10% 2382000 24-Mar-17 12.60%

18-Mar-17 12.40% 2115000 12-Nov-16 14.60%

21-Mar-17 16.30% 2437000 04-Nov-16 15.14%

22-Mar-17 20.20% 2428000 03-Nov-17 15.60%

24-Mar-17 12.60% 2374000 16-Mar-17 16.30%

25-Mar-17 11.90% 2083000 21-Mar-17 16.30%

02-Nov-17 11.30% 2404000 14-Mar-17 17.10%

03-Nov-17 15.60% 2318000 06-Jan-18 17.40%

06-Jan-18 17.40% 2243000 01-Nov-16 17.46%

10-Feb-18 18.60% 2426000 19-Feb-16 17.99%

11-Nov-16 18.16%

09-Nov-16 18.41%

10-Feb-18 18.60%

15-Mar-17 19.80%

22-Mar-17 20.20%

10-Nov-16 26.53%


Gas Flow date System Sendout

Net Injections/

(Withdrawals)

Storage Wdr

for Cust

Balancing

Core Forecast

Error

2/3/2016 3695000 -840000 119142 -7.10% 18 Total number

12/19/2016 3597000 -642000 229709 -1.20% 14 Total number <0

01/02/2017 3538000 -411000 -157642 -1.80% 78% Percentage <0

01/12/2017 3721000 -710000 -170358 0.30%

01/17/2017 3505000 -540000 -154162 -2.80% 8 Total number <-5%

01/22/2017 3685000 -528000 -434101 -17.60% 2 Total number <-10%

01/23/2017 4151000 -953000 -367420 -6.50% 44% Percentage <-5%

01/24/2017 4159000 -1127000 -165300 -4.50% 11% Percentage <-10%

01/25/2017 4057000 -919000 -125928 -4.10%

01/26/2017 3965000 -867000 -116301 -5.90%

01/27/2017 3739000 -652000 -162677 -13.00%

02/27/2017 3695000 -420000 -302950 -7.20%

12/21/2017 3575000 -857000 -153580 -5.40%

02/19/2018 3774000 -1064000 -370443 0.90%

02/20/2018 3745000 -1087000 -129324 1.00%

02/21/2018 3570000 -678000 133002 -3.40%

02/23/2018 3692000 -934000 -172028 -8.40%

02/27/2018 3728000 -947000 -124122 3.00%

Low OFOs at times of High System Flow

Att U CEYap WorkpapersHi flow Low OFOs Page 4

Flow Date Percent Error High OFO Tolerance Combined Noncore Customer Deviation During High OFOs

01-Nov-16 -16.5% 5%

22-Dec-16 -16.4% 5% -3.3% average over all days

10-Sep-16 -14.7% 5% 170 75% number of days with negative deviations

13-Feb-16 -14.6% 10% -5.5% average of negative deviations

02-Nov-16 -13.7% 5% 58 25% number of days with positive deviations

21-May-16 -13.6% 10% 3.1% average of positive deviations

07-Apr-17 -13.3% 5%

29-Oct-16 -12.9% 5% 219 96% number of days met tolerance

19-Feb-16 -12.5% 10%

12-Jan-18 -12.4% 5%

15-Jan-18 -12.2% 5% blue writing indicates both low OFO and high OFO on same day

10-Feb-18 -12.1% 5%

23-Mar-17 -11.8% 5%

05-Mar-16 -11.7% 10% Flow Date Percent Error High OFO Tolerance

02-May-17 -11.5% 5% 19-Feb-16 -12.5% 10%

27-Feb-16 -11.4% 10% 01-Nov-16 -16.5% 5%

18-Mar-17 -10.9% 5% 04-Nov-16 -8.4% 5%

20-May-16 -10.9% 10% 05-Nov-16 -5.6% 5%

14-Apr-18 -10.8% 5% 08-Nov-16 -1.7% 5%

16-Mar-17 -10.8% 5% 09-Nov-16 -7.7% 5%

20-Feb-16 -10.8% 10% 10-Nov-16 -5.1% 5%

16-Nov-16 -10.8% 5% 11-Nov-16 -5.4% 5%

15-Mar-17 -10.7% 5% 12-Nov-16 -5.0% 5%

18-Jun-17 -10.6% 5% 15-Nov-16 -2.9% 5%

24-Jun-17 -10.5% 5% 14-Mar-17 -8.3% 5%

17-Mar-16 -10.2% 10% 15-Mar-17 -10.7% 5%

16-Jul-16 -10.1% 5% 16-Mar-17 -10.8% 5%

28-May-16 -10.0% 10% 17-Mar-17 -9.6% 5%

10-Aug-16 -9.7% 5% 18-Mar-17 -10.9% 5%

10-Nov-17 -9.7% 5% 21-Mar-17 -6.7% 5%

09-Feb-17 -9.7% 5% 22-Mar-17 -5.8% 5%

17-Mar-17 -9.6% 5% 24-Mar-17 -5.5% 5%

28-Oct-16 -9.5% 5% 25-Mar-17 -2.6% 5%

Att U CEYap WorkpapersNoncore Dev Hi OFOs Page 5

11-Nov-17 -9.5% 5% 02-Nov-17 -7.8% 5%

17-May-16 -9.4% 10% 03-Nov-17 -5.9% 5%

06-Jan-18 -9.0% 5% 06-Jan-18 -9.0% 5%

16-Aug-17 -8.4% 5% 10-Feb-18 -12.1% 5%

12-Feb-16 -8.4% 10%

04-Nov-16 -8.4% 5%

14-Mar-17 -8.3% 5%

30-Jan-18 -8.3% 5%

15-Feb-17 -8.2% 5%

10-Sep-17 -8.2% 5%

19-Nov-16 -8.2% 5%

25-Oct-16 -7.8% 5%

02-Nov-17 -7.8% 5%

09-Nov-16 -7.7% 5%

28-Oct-17 -7.7% 5%

12-Mar-16 -7.7% 10%

13-Dec-16 -7.6% 5%

12-Mar-17 -7.3% 5%

22-Oct-16 -7.3% 5%

20-Feb-17 -7.2% 5%

21-Apr-17 -6.9% 5%

22-Apr-17 -6.8% 5%

08-Feb-17 -6.8% 5%

21-Mar-17 -6.7% 5%

21-Oct-16 -6.7% 5%

01-Nov-17 -6.3% 5%

22-May-17 -6.1% 5%

06-May-16 -6.1% 10%

31-Mar-17 -6.0% 5%

29-Jul-17 -5.9% 5%

03-Nov-17 -5.9% 5%

27-Jun-17 -5.8% 5%

30-Apr-16 -5.8% 10%

27-Oct-17 -5.8% 5%


23-Oct-16 -5.8% 5%

22-Mar-17 -5.8% 5%

27-Oct-16 -5.8% 5%

11-Mar-17 -5.6% 5%

05-Nov-16 -5.6% 5%

12-Oct-16 -5.6% 5%

14-May-16 -5.6% 10%

27-Apr-17 -5.5% 5%

08-Sep-16 -5.5% 5%

24-Jun-16 -5.5% 5%

24-Mar-17 -5.5% 5%

23-Jun-17 -5.4% 5%

22-Sep-16 -5.4% 5%

11-Nov-16 -5.4% 5%

29-Apr-18 -5.3% 5%

14-Oct-17 -5.3% 5%

06-May-17 -5.2% 5%

10-Nov-16 -5.1% 5%

09-Jul-17 -5.0% 5%

12-Nov-16 -5.0% 5%

16-Nov-17 -4.8% 5%

06-Aug-16 -4.7% 5%

28-Jun-17 -4.7% 5%

16-Apr-16 -4.6% 10%

29-Mar-17 -4.6% 5%

17-Sep-16 -4.6% 5%

19-Mar-16 -4.3% 10%

18-Apr-17 -4.2% 5%

11-Oct-16 -4.2% 5%

11-Mar-18 -4.2% 5%

20-Aug-16 -4.1% 5%

14-Jan-18 -4.1% 5%

17-Nov-16 -4.0% 5%

29-Jun-17 -4.0% 5%


14-Jun-17 -4.0% 5%

19-Mar-17 -3.8% 5%

04-Apr-17 -3.7% 5%

10-Mar-17 -3.6% 5%

07-May-16 -3.5% 10%

03-Sep-16 -3.4% 5%

25-Jul-17 -3.3% 5%

05-Feb-17 -3.3% 5%

09-Sep-17 -3.3% 5%

22-Jul-17 -3.2% 5%

27-Apr-18 -3.2% 5%

07-Sep-16 -3.1% 5%

29-Oct-17 -2.9% 5%

15-Nov-16 -2.9% 5%

12-Jul-17 -2.9% 5%

25-May-16 -2.9% 10%

08-Aug-17 -2.8% 5%

25-May-17 -2.7% 5%

31-May-17 -2.7% 5%

25-Mar-17 -2.6% 5%

21-May-17 -2.6% 5%

30-Mar-17 -2.4% 5%

27-Mar-16 -2.4% 10%

07-Aug-17 -2.3% 5%

11-May-16 -2.3% 10%

15-May-17 -2.2% 5%

28-Sep-16 -2.2% 5%

24-Jul-16 -2.1% 5%

02-Sep-16 -2.1% 5%

25-Aug-17 -2.1% 5%

22-Apr-16 -2.1% 10%

13-Jan-18 -2.1% 5%

16-Jun-17 -2.0% 5%

03-Jun-16 -2.0% 5%


13-Jun-17 -1.9% 5%

15-Apr-18 -1.9% 5%

30-Jun-17 -1.9% 5%

04-Mar-16 -1.8% 10%

26-Apr-16 -1.8% 10%

16-Jul-17 -1.8% 5%

08-Nov-16 -1.7% 5%

13-Apr-16 -1.7% 10%

24-Apr-17 -1.6% 5%

08-Mar-17 -1.6% 5%

17-Apr-17 -1.5% 5%

21-Aug-16 -1.5% 5%

31-Jul-16 -1.2% 5%

28-Apr-18 -1.2% 5%

06-Nov-16 -1.2% 5%

30-Oct-16 -1.2% 5%

27-Aug-16 -1.2% 5%

17-Jun-17 -1.1% 5%

22-Nov-16 -1.1% 5%

28-Mar-17 -1.1% 5%

14-Jul-17 -1.0% 5%

01-Apr-17 -1.0% 5%

26-Apr-17 -1.0% 5%

02-Jul-16 -1.0% 5%

17-Jun-16 -1.0% 5%

09-Aug-16 -0.9% 5%

08-Apr-17 -0.8% 5%

20-May-17 -0.8% 5%

31-Oct-17 -0.8% 5%

11-Jul-17 -0.4% 5%

21-Apr-16 -0.3% 10%

26-May-17 -0.2% 5%

07-Jun-17 -0.2% 5%

15-Sep-17 -0.1% 5%


26-Mar-17 -0.1% 5%

18-Nov-17 0.1% 5%

30-Jul-17 0.1% 5%

16-Mar-16 0.1% 10%

02-Dec-17 0.1% 5%

20-Apr-17 0.2% 5%

28-Nov-17 0.2% 5%

16-Dec-17 0.2% 5%

15-Aug-17 0.3% 5%

05-May-17 0.5% 5%

21-Oct-17 0.6% 5%

01-Mar-17 0.6% 5%

09-Jun-17 0.7% 5%

01-Dec-17 0.7% 5%

26-Mar-16 0.9% 10%

23-Jul-17 1.0% 5%

14-Feb-17 1.0% 5%

17-Nov-17 1.0% 5%

06-Jun-17 1.1% 5%

16-May-17 1.1% 5%

08-Oct-17 1.2% 5%

24-Aug-17 1.3% 5%

20-Oct-17 1.4% 5%

25-Nov-17 1.5% 5%

21-Nov-17 1.7% 5%

01-Jun-17 1.9% 5%

06-Aug-17 2.1% 5%

18-Jul-17 2.3% 5%

11-Jun-17 2.5% 5%

07-Jun-16 2.8% 5%

28-Jul-17 2.8% 5%

27-May-17 2.9% 5%

18-Nov-16 3.0% 5%

21-Jul-17 3.1% 5%


20-Aug-17 3.3% 5%

22-Nov-17 3.4% 5%

22-Jun-16 3.6% 5%

14-Nov-17 3.8% 5%

15-Jul-17 3.8% 5%

18-Jun-16 3.8% 5%

24-Nov-17 3.9% 5%

13-Aug-17 4.0% 5%

04-Jun-16 4.0% 5%

26-Nov-17 4.0% 5%

23-Apr-17 4.3% 5%

25-Dec-17 4.4% 5%

05-Nov-17 4.4% 5%

05-Aug-17 4.5% 5%

04-Nov-17 4.6% 5%

15-Nov-17 4.7% 5%

04-Sep-17 5.3% 5%

24-Sep-16 5.5% 5%

09-Dec-17 5.6% 5%

28-May-17 5.7% 5%

31-Mar-18 6.2% 5%

22-Oct-17 8.4% 5%

19-Nov-17 9.4% 5%

06-Jun-16 13.3% 5%

05-Jun-16 15.8% 5%


Flow Date Percent ErrorLow OFO Tolerance Combined Noncore Customer Deviation During Low OFOs

16-Oct-17 -15.99% -5% 4.9% average over all dates

09-Apr-18 -14.21% -5% 179 79% number of dates where deviation is positive

11-Sep-17 -13.12% -5% 7.2% average positive deviation

12-Feb-18 -10.78% -5% 47 21% number of dates where deviation is negative

25-Oct-16 -7.83% -5% -3.9% average negative deviation

23-Oct-17 -7.01% -5%

01-Oct-16 -6.94% -5% 213 94% number of days met tolerance

21-Mar-18 -6.85% -5%

21-Oct-16 -6.67% -5%

22-May-17 -6.12% -5% blue writing indicates both low OFO and high OFO on same day

16-Jan-18 -6.04% -5%

27-Jun-17 -5.84% -5%

29-Aug-16 -5.28% -5% Flow Date Percent ErrorLow OFO Tolerance

30-Dec-16 -4.88% -5% 03-Feb-16 13.83% -9%

29-Mar-17 -4.57% -5% 19-Dec-16 12.98% -5%

13-Feb-18 -4.56% -5% 02-Jan-17 5.92% -5%

20-Mar-18 -4.00% -5% 12-Jan-17 -0.86% -5%

29-Sep-16 -3.84% -5% 17-Jan-17 2.90% -5%

13-Feb-17 -3.70% -5% 22-Jan-17 -1.92% -5%

13-Mar-17 -3.54% -5% 23-Jan-17 9.01% -5%

07-Jan-17 -3.25% -5% 24-Jan-17 7.51% -5%

10-Mar-18 -3.20% -5% 25-Jan-17 5.42% -5%

19-Sep-16 -3.19% -5% 26-Jan-17 3.26% -5%

19-Mar-18 -2.84% -5% 27-Jan-17 6.26% -5%

24-Oct-16 -2.62% -5% 27-Feb-17 0.10% -5%

11-Oct-17 -2.60% -5% 21-Dec-17 4.23% -5%

30-Mar-17 -2.41% -5% 19-Feb-18 0.23% -5%

29-Jan-18 -2.37% -5% 20-Feb-18 1.20% -5%

28-Sep-16 -2.17% -5% 21-Feb-18 21.32% -5%

05-Feb-18 -2.05% -5% 23-Feb-18 8.26% -5%

03-Jun-16 -2.02% -5% 27-Feb-18 3.83% -5%

22-Jan-17 -1.92% -5%

08-Mar-17 -1.61% -5%

Att U CEYap WorkpapersNoncore Dev Low OFOs Page 12

17-Apr-17 -1.54% -5% Flow Date Percent ErrorLow OFO Tolerance

07-Jul-17 -1.38% -5% 22-Jan-17 -1.92% -5%

17-Jun-16 -1.02% -5% 12-Jan-17 -0.86% -5%

16-Aug-16 -0.89% -5% 27-Feb-17 0.10% -5%

12-Jan-17 -0.86% -5% 19-Feb-18 0.23% -5%

26-Sep-16 -0.82% -5% 20-Feb-18 1.20% -5%

26-Oct-16 -0.73% -5% 17-Jan-17 2.90% -5%

22-Mar-18 -0.60% -5% 26-Jan-17 3.26% -5%

02-Mar-18 -0.50% -5% 27-Feb-18 3.83% -5%

23-Apr-18 -0.49% -5% 21-Dec-17 4.23% -5%

19-Apr-18 -0.49% -5% 25-Jan-17 5.42% -5%

29-Jul-16 -0.35% -5% 02-Jan-17 5.92% -5%

16-Mar-18 -0.28% -5% 27-Jan-17 6.26% -5%

25-Sep-17 -0.15% -5% 24-Jan-17 7.51% -5%

27-Feb-17 0.10% -5% 23-Feb-18 8.26% -5%

19-Jun-17 0.11% -5% 23-Jan-17 9.01% -5%

28-Aug-17 0.15% -5% 19-Dec-16 12.98% -5%

20-Apr-17 0.19% -5% 03-Feb-16 13.83% -9%

07-Mar-17 0.22% -5% 21-Feb-18 21.32% -5%

19-Feb-18 0.23% -5%

27-Mar-18 0.28% -5%

17-Feb-18 0.38% -5%

16-Apr-18 0.42% -5%

29-Mar-18 0.48% -5%

24-Jan-18 0.56% -5%

01-Mar-17 0.57% -5%

06-Sep-16 0.61% -5%

26-Mar-18 0.64% -5%

09-Jan-18 0.71% -5%

26-Jun-17 0.71% -5%

01-May-17 0.72% -5%

01-Sep-17 0.74% -5%

19-Dec-17 0.78% -5%

29-Jan-17 1.00% -5%


14-Mar-18 1.03% -5%

21-Aug-17 1.16% -5%

20-Feb-18 1.20% -5%

07-Dec-17 1.23% -5%

08-Feb-18 1.30% -5%

30-Sep-16 1.32% -5%

17-Apr-18 1.51% -5%

21-Dec-16 1.54% -5%

06-Nov-17 1.58% -5%

30-Jan-17 1.60% -5%

27-Jun-16 1.66% -5%

12-Dec-16 1.69% -5%

26-Oct-17 1.75% -5%

10-Apr-17 1.77% -5%

25-Jan-18 1.82% -5%

28-Jan-17 2.02% -5%

27-Jul-16 2.05% -5%

23-Mar-18 2.15% -5%

08-Dec-16 2.34% -5%

17-Oct-16 2.36% -5%

31-Dec-16 2.36% -5%

18-Feb-17 2.38% -5%

14-Aug-16 2.38% -5%

25-Mar-18 2.46% -5%

23-Jan-18 2.48% -5%

26-Jul-16 2.61% -5%

18-Jul-16 2.64% -5%

10-Apr-18 2.70% -5%

20-Jun-17 2.71% -5%

27-Jan-18 2.74% -5%

28-Sep-17 2.81% -5%

17-Jan-17 2.90% -5%

17-Feb-17 2.90% -5%

23-Dec-16 2.91% -5%


29-Aug-17 3.09% -5%

05-Apr-17 3.16% -5%

26-Jan-17 3.26% -5%

07-Mar-18 3.27% -5%

20-Sep-16 3.35% -5%

19-Jan-18 3.45% -5%

25-Apr-18 3.53% -5%

26-Jan-18 3.66% -5%

06-Mar-18 3.83% -5%

27-Feb-18 3.83% -5%

14-Nov-17 3.83% -5%

07-Feb-17 4.03% -5%

22-Jan-18 4.04% -5%

01-Mar-18 4.07% -5%

15-Mar-18 4.13% -5%

18-Dec-17 4.14% -5%

16-Feb-18 4.15% -5%

02-Jan-18 4.18% -5%

21-Dec-17 4.23% -5%

19-Aug-16 4.27% -5%

25-Dec-17 4.41% -5%

09-Jan-17 4.41% -5%

30-Aug-16 4.44% -5%

09-Mar-18 4.51% -5%

03-Apr-18 4.61% -5%

28-Jul-16 4.69% -5%

08-Jan-18 5.08% -5%

12-Dec-17 5.25% -5%

24-Mar-18 5.25% -5%

25-Jan-17 5.42% -5%

09-Mar-17 5.43% -5%

26-Apr-18 5.55% -5%

20-Dec-17 5.75% -5%

30-Jun-16 5.81% -5%


17-Aug-16 5.83% -5%

06-Mar-16 5.90% -12%

02-Jan-17 5.92% -5%

14-Jul-16 5.97% -5%

14-Feb-18 5.98% -5%

07-Mar-16 6.25% -10%

22-Dec-17 6.26% -5%

27-Jan-17 6.26% -5%

20-Jul-16 6.30% -5%

19-Jul-16 6.31% -5%

05-Dec-16 6.50% -5%

07-Jul-16 6.51% -5%

03-Dec-16 6.53% -5%

19-Oct-16 6.53% -5%

13-Jun-16 6.55% -5%

27-Aug-17 6.58% -5%

20-Dec-16 6.74% -5%

15-Aug-16 6.92% -5%

30-Jul-16 6.97% -5%

18-Sep-17 6.98% -5%

02-Mar-17 7.08% -5%

05-Mar-18 7.09% -5%

14-Dec-17 7.31% -5%

28-Feb-17 7.41% -5%

24-Jan-17 7.51% -5%

01-Dec-16 7.53% -5%

27-Dec-16 7.67% -5%

27-Sep-16 7.80% -5%

05-Oct-16 8.09% -5%

23-Feb-18 8.26% -5%

05-Jun-17 8.28% -5%

02-Feb-17 8.35% -5%

28-Dec-16 8.52% -5%

15-Dec-17 8.56% -5%


11-Dec-17 8.84% -5%

21-Jan-18 8.88% -5%

03-Oct-16 9.00% -5%

23-Jan-17 9.01% -5%

15-Feb-18 9.15% -5%

23-Dec-17 9.20% -5%

04-Mar-18 9.60% -5%

22-Aug-16 9.92% -5%

12-Jul-16 9.92% -5%

03-Mar-17 9.97% -5%

29-Jun-16 10.04% -5%

08-Jun-16 10.05% -5%

19-Apr-17 10.10% -5%

12-Apr-18 10.16% -5%

03-Mar-18 10.53% -5%

24-Apr-18 10.84% -5%

03-Apr-17 10.85% -5%

05-Mar-17 10.92% -5%

04-Dec-17 11.07% -5%

08-Aug-16 11.07% -5%

04-Dec-16 11.19% -5%

14-Feb-16 11.20% -15%

04-Mar-17 11.21% -5%

01-Feb-18 11.31% -5%

02-Apr-18 11.75% -5%

01-Jun-16 12.07% -5%

13-Dec-17 12.39% -5%

22-Jul-16 12.56% -5%

19-Dec-16 12.98% -5%

02-Apr-17 13.07% -5%

05-Dec-17 13.34% -5%

03-Feb-16 13.83% -9%

26-Feb-18 14.08% -5%

20-Jan-18 14.32% -5%


27-Nov-16 14.95% -5%

20-Jun-16 15.38% -5%

27-Mar-17 15.59% -5%

16-Jun-16 15.99% -5%

18-Feb-18 16.00% -5%

23-Aug-17 16.33% -5%

20-Mar-17 16.39% -5%

05-Jul-16 16.76% -5%

08-Dec-17 17.91% -5%

21-Jun-17 18.65% -5%

24-Dec-17 18.95% -5%

21-Nov-16 20.21% -5%

19-Jun-16 20.69% -5%

25-Feb-18 20.74% -5%

29-Nov-16 21.00% -5%

01-Jan-17 21.17% -5%

21-Feb-18 21.32% -5%

23-Jul-16 22.26% -5%

24-Dec-16 23.55% -5%

28-Nov-16 23.82% -5%

05-Feb-16 24.30% -10%

22-Feb-18 24.93% -5%

31-Oct-16 30.30% -5%


No of low OFOs No of high OFOs Both low & high Total OFOs Percentage

April 1, 2016-March 31, 2017 106 98 -9 195 53%

April 1, 2017-March 31, 2018 102 112 -5 209 57%

Att U CEYap WorkpapersOFO percentage Page 19

On a cold day, the noncore base stays about the same because usage is not tempature sensitive. The core loads & temperature sensitivewholesale loads (wholesale core) increase. Thus as an approximation, we can take the difference between the average daily January usageand average daily December usage and attribute it to the core and wholesale temperature sensitive loads on a high flow day. This is consistentthe comparison between the average Jan or Dec daily core loads and the peak cold day core loads that is reported in the CGR for planning purposes.We attribute 94.5% of increased high flow day loads to core and of that 92.3% of the core loads to GA.

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Deccombined core 1,620 1,583 1,310 1,149 867 792 721 696 719 814 1,220 1,687 94.5% 94.4% 94.6% 94.5%Other whlsl temp sensitive 95 94 77 66 50 46 45 45 47 50 68 97 5.5% 5.6% 5.4% 5.5%

Total temp sensitive 1,715 1,677 1,387 1,215 917 838 766 741 766 864 1,288 1,784Retail noncore 1,151 1,112 1,031 1,026 1,055 1,076 1,336 1,366 1,486 1,292 1,090 1,110 140SDG&E noncore 170 152 134 139 146 192 198 201 215 205 164 171 174Other wholesale temp insensitive 33 33 33 33 33 33 33 33 33 33 33 33Company use 42 41 36 33 29 30 32 33 35 33 36 43Total 3,111 3,015 2,621 2,446 2,180 2,169 2,365 2,374 2,535 2,427 2,611 3,141 Total not temp sensitive 1,396 1,338 1,234 1,231 1,263 1,331 1,599 1,633 1,769 1,563 1,323 1,357

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov DecCore 1,420 1,379 1,143 999 748 689 627 605 626 711 1,066 1,475Core variation 60% 60% 24% 7% -27% -41% -45% -45% -44% -31% 13% 72%Core less base (avg summer) use 801 760 524 380 129 70 8 14 7 92 447 856

average min summer mo core loadaverage nonsummer noncore load Jan Feb Mar Apr May Jun Nov Dec

NC nonsummer variation 6% 3% -5% -5% -2% 0% 1% 3%

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec avgwholesale incl international 501 486 414 391 350 377 373 373 391 394 422 517 415SDG&E core 200 204 167 150 119 103 94 91 93 103 154 212 140SDG&E noncore 170 152 134 139 146 192 198 201 215 205 164 171 174SDG&E LUAF 3 3 3 3 2 3 3 3 3 3 3 4 3wholesale excl SDG&E 128 127 110 99 83 79 78 78 80 83 101 130 98

Long Beach 34 34 28 24 18 15 15 15 15 17 25 37 23SWG 27 27 21 18 12 10 9 9 10 12 19 29 17Vernon 9 9 9 9 9 9 9 9 9 9 9 9 9Ecogas 25 25 25 25 25 25 25 25 25 25 25 25 25Other 33 32 28 23 19 20 21 21 22 21 23 31 25

LB about 8.7 bcf/yr or 19 MMcfd core 4 MMcfd NC19 weather related core load also noncore4SWG about 6.2 bcf/yr 16.9863 weather relatedVernon about 3.2 bcf/yr 8.767123 not weather relatedEcogas about 9.0 bcf/yr 24.65753 not weather related

Att U CEYap WorkpapersCGR Page 20

Gas Flow

Date

System

Sendout

Non Temp

Sensitive

Usage

Estimated

Actual Retail

Core Usage

Retail Core

Forecast

Deviation

105% of

Forecast Usage

Gas

Acquisition

Over-Delivery

System

High OFO

Tolerance

Over-

Delivery/

Tolerance

Gas Flow

Date

Core

Forecast

Error

System

Sendout

Non Temp

Sensitive

Usage

Temp

Sensitive

Usage

Core share1

of Temp

Sens Usage

GA share2

of Core

Share

Forecast

Level

105% of

Forecast

Level

Est GA

Delivery

Deviation

Est GA

Delivery

Excess

System

High OFO

Tolerance

MMcf/d MMcf/d MMcf/d MMcf/d MMcf/d MMcf/d MMcf/d MMcf/d MMcf/d MMcf/d MMcf/d MMcf/d MMcf/d MMcf/d MMcf/d MMcf/d

(A) (B) (C ) (D)=(B-C)x90% (E )

(F)=(Dx(1+E))x1.05 (G)=(F-D) (H) (I = G / H) 2/19/2016 17.99% 2,397 1,338 1,059 1,000 940 1,109 1,165 23.9% 225 187 1.20

2/19/2016 2,397 1,338 940 18.0% 1,165 225 187 120% 11/1/2016 17.46% 2,389 1,323 1,066 1,007 947 1,112 1,167 23.3% 221 25 8.83

11/1/2016 2,389 1,323 947 17.5% 1,167 221 25 883% 11/4/2016 15.14% 2,326 1,323 1,003 947 891 1,025 1,077 20.9% 186 190 0.98

11/4/2016 2,326 1,323 891 15.1% 1,077 186 190 98% 11/5/2016 11.17% 2,184 1,323 861 813 764 850 892 16.7% 128 226 0.57

11/5/2016 2,184 1,323 764 11.2% 892 128 226 57% 11/8/2016 11.15% 2,504 1,323 1,181 1,116 1,049 1,166 1,224 16.7% 175 185 0.95

11/8/2016 2,504 1,323 1,049 11.1% 1,224 175 185 95% 11/9/2016 18.41% 2,588 1,323 1,265 1,195 1,123 1,330 1,397 24.3% 273 185 1.48

11/9/2016 2,588 1,323 1,123 18.4% 1,397 273 185 148% 11/10/2016 26.53% 2,460 1,323 1,137 1,074 1,010 1,277 1,341 32.9% 332 185 1.79

11/10/2016 2,460 1,323 1,010 26.5% 1,341 332 185 179% 11/11/2016 18.16% 2,380 1,323 1,057 998 939 1,109 1,164 24.1% 226 185 1.22

11/11/2016 2,380 1,323 939 18.2% 1,164 226 185 122% 11/12/2016 14.60% 2,153 1,323 830 784 737 844 887 20.3% 150 185 0.81

11/12/2016 2,153 1,323 737 14.6% 887 150 185 81% 11/15/2016 10.41% 2,487 1,323 1,164 1,100 1,034 1,141 1,198 15.9% 165 185 0.89

11/15/2016 2,487 1,323 1,034 10.4% 1,198 165 185 89% 3/14/2017 17.10% 2,526 1,234 1,292 1,220 1,147 1,343 1,411 23.0% 263 114 2.31

3/14/2017 2,526 1,234 1,147 17.1% 1,411 263 114 231% 3/15/2017 19.80% 2,494 1,234 1,260 1,190 1,119 1,340 1,407 25.8% 289 72 4.01

3/15/2017 2,494 1,234 1,119 19.8% 1,407 289 72 401% 3/16/2017 16.30% 2,462 1,234 1,228 1,160 1,090 1,268 1,332 22.1% 241 72 3.35

3/16/2017 2,462 1,234 1,090 16.3% 1,332 241 72 335% 3/17/2017 10.10% 2,382 1,234 1,148 1,084 1,019 1,122 1,178 15.6% 159 72 2.21

3/17/2017 2,382 1,234 1,019 10.1% 1,178 159 72 221% 3/18/2017 12.40% 2,115 1,234 881 832 782 879 923 18.0% 141 72 1.96

3/18/2017 2,115 1,234 782 12.4% 923 141 72 196% 3/21/2017 16.30% 2,437 1,234 1,203 1,136 1,068 1,242 1,304 22.1% 236 72 3.28

3/21/2017 2,437 1,234 1,068 16.3% 1,304 236 72 328% 3/22/2017 20.20% 2,428 1,234 1,194 1,128 1,060 1,274 1,338 26.2% 278 72 3.86

3/22/2017 2,428 1,234 1,060 20.2% 1,338 278 72 386% 3/24/2017 12.60% 2,374 1,234 1,140 1,077 1,012 1,140 1,197 18.2% 185 72 2.56

3/24/2017 2,374 1,234 1,012 12.6% 1,197 185 72 256% 3/25/2017 11.90% 2,083 1,234 849 802 754 843 886 17.5% 132 123 1.07

3/25/2017 2,083 1,234 754 11.9% 886 132 123 107% 11/2/2017 11.30% 2,404 1,323 1,081 1,021 960 1,068 1,122 16.9% 162 149 1.09

11/2/2017 2,404 1,323 960 11.3% 1,122 162 149 109% 11/3/2017 15.60% 2,318 1,323 995 940 883 1,021 1,072 21.4% 189 134 1.41

11/3/2017 2,318 1,323 883 15.6% 1,072 189 134 141% 1/6/2018 17.40% 2,243 1,396 847 800 752 883 927 23.3% 175 134 1.31

1/6/2018 2,243 1,396 752 17.4% 927 175 134 131% 2/10/2018 18.60% 2,426 1,338 1,088 1,028 966 1,146 1,203 24.5% 237 156 1.52

2/10/2018 2,426 1,338 966 18.6% 1,203 237 156 152% 2016-2017 winter avg 21.3% 210 127

2016-2017 winter avg 210 127 234%1

Core share is 95.5 percent 2

Gas Acquisition share is 94 percent 2017-2018 winter avg 21.5% 191 143

2017-2018 winter avg 191 143 133%

Estimate of Potential Gas Acquisition Delivery Deficit on Winter High OFO Days Estimate of Potential Gas Acquisition Delivery Deficit on Winter High OFO Days

Att U CEYap WorkpapersTable 1 Page 21

Gas Flow

Date

System

Sendout

Gas

Acquisition

Over-

Delivery

Noncore

Delivery

Deviation

Combined Gas

Acquisition/

Noncore Delivery

Deviation

System

High OFO

Tolerance

Combined Gas

Acquisition &

Noncore Delivery

Deviation/

Gas Flow

Date

System

Sendout

Non Temp

Sensitive

Usage

Estimated

Core Usage Core Forecast

105% of

Forecast Usage

Core

Delivery

Excess

System

High OFO

Tolerance

Deficit/

Tolerance

MMcf/d MMcf/d MMcf/d MMcf/d MMcf/d Tolerance MMcf/d MMcf/d MMcf/d Deviation MMcf/d MMcf/d MMcf/d

(A) (B) (C ) (D) (E=C+D) (F) (G=E/F) (A) (B) (C ) (D)=(B-C)x90% (E )

(F)=(Dx(1+E))x1.05 (G)=(F-D) (H) (I)

2/19/2016 2,397 225 -167 58 187 31% 2/19/2016 2,397 1,338 940 18.0% 1,165 225 187 120%

11/1/2016 2,389 221 -219 2 25 7% 16 11/1/2016 2,389 1,323 947 17.5% 1,167 221 25 883%

11/4/2016 2,326 186 -111 75 190 39% 23 11/4/2016 2,326 1,323 891 15.1% 1,077 186 190 98%

11/5/2016 2,184 128 -75 53 226 24% 70% 11/5/2016 2,184 1,323 764 11.2% 892 128 226 57%

11/8/2016 2,504 175 -23 152 185 82% 11/8/2016 2,504 1,323 1,049 11.1% 1,224 175 185 95%

11/9/2016 2,588 273 -102 171 185 93% 11/9/2016 2,588 1,323 1,123 18.4% 1,397 273 185 148%

11/10/2016 2,460 332 -67 264 185 143% 11/10/2016 2,460 1,323 1,010 26.5% 1,341 332 185 179%

11/11/2016 2,380 226 -71 155 185 84% 11/11/2016 2,380 1,323 939 18.2% 1,164 226 185 122%

11/12/2016 2,153 150 -66 84 185 46% 11/12/2016 2,153 1,323 737 14.6% 887 150 185 81%

11/15/2016 2,487 165 -39 126 185 68% 11/15/2016 2,487 1,323 1,034 10.4% 1,198 165 185 89%

3/14/2017 2,526 263 -103 161 114 141% 3/14/2017 2,526 1,234 1,147 17.1% 1,411 263 114 231%

3/15/2017 2,494 289 -132 157 72 218% 3/15/2017 2,494 1,234 1,119 19.8% 1,407 289 72 401%

3/16/2017 2,462 241 -133 108 72 150% 3/16/2017 2,462 1,234 1,090 16.3% 1,332 241 72 335%

3/17/2017 2,382 159 -119 40 72 56% 3/17/2017 2,382 1,234 1,019 10.1% 1,178 159 72 221%

3/18/2017 2,115 141 -135 6 72 8% 3/18/2017 2,115 1,234 782 12.4% 923 141 72 196%

3/21/2017 2,437 236 -83 153 72 213% 3/21/2017 2,437 1,234 1,068 16.3% 1,304 236 72 328%

3/22/2017 2,428 278 -71 207 72 287% 3/22/2017 2,428 1,234 1,060 20.2% 1,338 278 72 386%

3/24/2017 2,374 185 -67 117 72 163% 3/24/2017 2,374 1,234 1,012 12.6% 1,197 185 72 256%

3/25/2017 2,083 132 -33 99 123 81% 3/25/2017 2,083 1,234 754 11.9% 886 132 123 107%

11/2/2017 2,404 162 -103 59 149 39% 11/2/2017 2,404 1,323 960 11.3% 1,122 162 149 109%

11/3/2017 2,318 189 -78 111 134 83% 11/3/2017 2,318 1,323 883 15.6% 1,072 189 134 141%

1/6/2018 2,243 175 -126 49 134 37% 1/6/2018 2,243 1,396 752 17.4% 927 175 134 131%

2/10/2018 2,426 237 -162 75 156 48% 2/10/2018 2,426 1,338 966 18.6% 1,203 237 156 152%

2016-2017 winter avg 210 127 234%

2017-2018 winter avg 191 143 133%

Estimate of Potential Gas Acquisition Delivery Deficit on Winter High OFO Days Comparison of Core & Noncore Delivery Deviation on Winter High OFO Days


Estimate of Potential Gas Acquisition Delivery Deficit on Low OFO Days with Greater Than 3.5 Bcf/d System Sendout

Gas Flow

Date

System

Sendout

Non Temp

Sensitive

Usage

Estimated

Actual Retail


95% of

Forecast Usage

Gas Acquisition

Under-Delivery

System

Low OFO

Tolerance

Under-

Delivery/

Tolerance

Gas Flow

Date

Core

Forecast

Error

System

Sendout

Non Temp

Sensitive

Usage

Temp

Sensitive

Usage

Core share1

of Temp

Sens Usage

GA share2

of Core

Share

Forecast

Level

95% of

Forecast

Level

Est GA

Delivery

Deviation

Est GA

Delivery

Deficit

System

Low OFO

Tolerance

MMcf/d MMcf/d MMcf/d Deviation MMcf/d MMcf/d MMcf/d MMcf/d MMcf/d MMcf/d MMcf/d MMcf/d MMcf/d MMcf/d MMcf/d MMcf/d

(A) (B) (C ) (D)=(B-C)x90% (E )

(F)=(Dx(1+E))x.95 (G)=(F-D) (H) (I = G / H) 2/3/2016 -7.10% 3,695 1,338 2,357 2,227 2,055 1,909 1,814 -11.7% (241.48) 348 69%

2/3/2016 3,695 1,338 2,055 -7.1% 1,814 241 348 69% 12/19/2016 -1.20% 3,597 1,357 2,240 2,116 1,953 1,930 1,833 -6.1% (119.94) 261 46%

12/19/2016 3,597 1,357 1,953 -1.2% 1,833 120 261 46% 01/02/2017 -1.80% 3,538 1,396 2,142 2,024 1,868 1,834 1,743 -6.7% (125.33) 261 48%

01/02/2017 3,538 1,396 1,868 -1.8% 1,743 125 261 48% 01/12/2017 0.30% 3,721 1,396 2,325 2,197 2,027 2,034 1,932 -4.7% (95.60) 261 37%

01/12/2017 3,721 1,396 2,027 0.3% 1,932 96 261 37% 01/17/2017 -2.80% 3,505 1,396 2,109 1,993 1,839 1,788 1,698 -7.7% (140.87) 261 54%

01/17/2017 3,505 1,396 1,839 -2.8% 1,698 141 261 54% 01/22/2017 -17.60% 3,685 1,396 2,289 2,163 1,996 1,645 1,563 -21.7% (433.55) 203 213%

01/22/2017 3,685 1,396 1,996 -17.6% 1,563 434 203 213% 01/23/2017 -6.50% 4,151 1,396 2,755 2,603 2,403 2,246 2,134 -11.2% (268.48) 203 132%

01/23/2017 4,151 1,396 2,403 -6.5% 2,134 268 203 132% 01/24/2017 -4.50% 4,159 1,396 2,763 2,611 2,410 2,301 2,186 -9.3% (223.48) 203 110%

01/24/2017 4,159 1,396 2,410 -4.5% 2,186 223 203 110% 01/25/2017 -4.10% 4,057 1,396 2,661 2,514 2,321 2,225 2,114 -8.9% (206.41) 203 101%

01/25/2017 4,057 1,396 2,321 -4.1% 2,114 206 203 101% 01/26/2017 -5.90% 3,965 1,396 2,569 2,427 2,240 2,108 2,003 -10.6% (237.58) 208 114%

01/26/2017 3,965 1,396 2,240 -5.9% 2,003 238 208 114% 01/27/2017 -13.00% 3,739 1,396 2,343 2,214 2,043 1,778 1,689 -17.4% (354.49) 231 153%

01/27/2017 3,739 1,396 2,043 -13.0% 1,689 354 231 153% 02/27/2017 -7.20% 3,695 1,338 2,357 2,227 2,055 1,907 1,812 -11.8% (243.36) 203 120%

02/27/2017 3,695 1,338 2,055 -7.2% 1,812 243 203 120% 12/21/2017 -5.40% 3,575 1,357 2,218 2,096 1,934 1,830 1,738 -10.1% (195.93) 251 78%

12/21/2017 3,575 1,357 1,934 -5.4% 1,738 196 251 78% 02/19/2018 0.90% 3,774 1,338 2,436 2,302 2,124 2,143 2,036 -4.1% (88.05) 232 38%

02/19/2018 3,774 1,338 2,124 0.9% 2,036 88 232 38% 02/20/2018 1.00% 3,745 1,338 2,407 2,274 2,099 2,120 2,014 -4.0% (85.01) 232 37%

02/20/2018 3,745 1,338 2,099 1.0% 2,014 85 232 37% 02/21/2018 -3.40% 3,570 1,338 2,232 2,109 1,946 1,880 1,786 -8.2% (160.19) 232 69%

02/21/2018 3,570 1,338 1,946 -3.4% 1,786 160 232 69% 02/23/2018 -8.40% 3,692 1,338 2,354 2,224 2,053 1,880 1,786 -13.0% (266.45) 205 130%

02/23/2018 3,692 1,338 2,053 -8.4% 1,786 266 205 130% 02/27/2018 3.00% 3,728 1,338 2,390 2,258 2,084 2,147 2,039 -2.2% (44.81) 203 22%

02/27/2018 3,728 1,338 2,084 3.0% 2,039 45 203 22% 2016-2017 winter avg -10.6% (222.65) 227

2016-2017 winter avg 223 227 103%1

Core share is 95.5 percent 2

Gas Acquisition share is 94 percent 2017-2018 winter avg -6.9% (140.07) 226

2017-2018 winter avg 140 226 62% These are high sendout low OFO days




Gas Flow

Date

System

Sendout

Gas

Acquisition

Under-

Delivery

Noncore

Delivery

Deviation

Combined Gas

Acquisition/

Noncore Delivery

Deviation

System

Low OFO

Tolerance

Combined Gas

Acquisition &

Noncore Delivery

Deviation/

Gas Flow

Date

System

Sendout

Non Temp

Sensitive

Usage

Estimated


95% of Forecast

Usage

Core

Delivery

Deficit

System

Low OFO

Tolerance

Deficit/

Tolerance

MMcf/d MMcf/d MMcf/d MMcf/d MMcf/d Tolerance MMcf/d MMcf/d MMcf/d Deviation MMcf/d MMcf/d MMcf/d

(A) (B) (C ) (D) (E=C+D) (F) (G=E/F) (A) (B) (C ) (D)=(B-C)x90% (E )

(F)=(Dx(1+E))x.95 (G)=(F-D) (H) (I)

2/3/2016 3,695 -241 185 -56 -348 16% 2/3/2016 3,695 1,338 2,055 -7.1% 1,814 241 348 69%

12/19/2016 3,597 -120 176 56 -261 -22% 12/19/2016 3,597 1,357 1,953 -1.2% 1,833 120 261 46%

01/02/2017 3,538 -125 83 -43 -261 16% 01/02/2017 3,538 1,396 1,868 -1.8% 1,743 125 261 48%

01/12/2017 3,721 -96 -12 -108 -261 41% 01/12/2017 3,721 1,396 2,027 0.3% 1,932 96 261 37%

01/17/2017 3,505 -141 40 -100 -261 39% 01/17/2017 3,505 1,396 1,839 -2.8% 1,698 141 261 54%

01/22/2017 3,685 -434 -27 -460 -203 226% 01/22/2017 3,685 1,396 1,996 -17.6% 1,563 434 203 213%

01/23/2017 4,151 -268 126 -143 -203 70% 01/23/2017 4,151 1,396 2,403 -6.5% 2,134 268 203 132%

01/24/2017 4,159 -223 105 -119 -203 58% 01/24/2017 4,159 1,396 2,410 -4.5% 2,186 223 203 110%

01/25/2017 4,057 -206 76 -131 -203 64% 01/25/2017 4,057 1,396 2,321 -4.1% 2,114 206 203 101%

01/26/2017 3,965 -238 46 -192 -208 92% 01/26/2017 3,965 1,396 2,240 -5.9% 2,003 238 208 114%

01/27/2017 3,739 -354 87 -267 -231 115% 01/27/2017 3,739 1,396 2,043 -13.0% 1,689 354 231 153%

02/27/2017 3,695 -243 1 -242 -203 119% 02/27/2017 3,695 1,338 2,055 -7.2% 1,812 243 203 120%

12/21/2017 3,575 -196 57 -139 -251 55% 12/21/2017 3,575 1,357 1,934 -5.4% 1,738 196 251 78%

02/19/2018 3,774 -88 3 -85 -232 37% 02/19/2018 3,774 1,338 2,124 0.9% 2,036 88 232 38%

02/20/2018 3,745 -85 16 -69 -232 30% 02/20/2018 3,745 1,338 2,099 1.0% 2,014 85 232 37%

02/21/2018 3,570 -160 285 125 -232 -54% 02/21/2018 3,570 1,338 1,946 -3.4% 1,786 160 232 69%

02/23/2018 3,692 -266 111 -156 -205 76% 02/23/2018 3,692 1,338 2,053 -8.4% 1,786 266 205 130%

02/27/2018 3,728 -45 51 6 -203 -3% 02/27/2018 3,728 1,338 2,084 3.0% 2,039 45 203 22%

2016-2017 winter avg 223 227 103%

2017-2018 winter avg 140 226 62%

Comparison of Core & Noncore Delivery Deviation

on Low OFO Days with Greater Than 3.5 Bcf/d System Sendout


Nominations Are Due Via EBB at These Times

Timely Cycle 11:00 a.m. one day prior to gas day

Evening Cycle 4:00 p.m. one day prior to gas day

Intraday 1 Cycle 8:00 a.m. on the gas day

Intraday 2 Cycle 12:30 p.m. on the gas day




Calculations Based on Figure 2 & underlying data

max 44.6% 7.5% mape for Dec 2011 through Nov 2015

min -29.8% 3.8%

max 43.8% 6.6% mape for Jan 2016 through Dec 2017

min -17.6%

avg winter day cold month 1,595 319.000 core deviation at 20%

peak cold day 3,312 662.400 core deviation at 20%

294.44 Gas Procurement share


478.50 core deviation at 30%

993.60 core deviation at 30%



140

0.95

133

1.40

2 deviations are less than -29%

1% 26 deviations are less than -20%

10% 264 deviations are less than -10% but greater than -20%

39% 1054 deviations are less than 0% but greater than -10%

35% 941 deviations are greater than 0% but less than 10%

12% 322 deviations are greater than 10% but less than 20%

3% 67 deviations are greater than 20%

13 deviations are greater than 30%

100% 2677

50% 2674

50% 44.6%

-29.8%

Att U CEYap WorkpapersFig 2 Page 26

Data supporting Figure 2 and associated calculations

Date % Diff Date % Diff Date % Diff Date % Diff Date % Diff Date % Diff Date % Diff Date % Diff

1/1/2011 -7.1% 1/1/2012 -6.6% 1/1/2013 -1.5% 1/1/2014 -2.3% 1/1/2015 0.9% 1/1/2016 3.7% 1/1/2017 11.20% 1/1/2018 4.70%

1/2/2011 9.6% 1/2/2012 0.7% 1/2/2013 3.5% 1/2/2014 2.0% 1/2/2015 0.5% 1/2/2016 -5.1% 1/2/2017 -1.80% 1/2/2018 3.10%

1/3/2011 -0.7% 1/3/2012 -4.6% 1/3/2013 5.9% 1/3/2014 -0.6% 1/3/2015 3.0% 1/3/2016 0.9% 1/3/2017 -7.00% 1/3/2018 7.20%

1/4/2011 -0.7% 1/4/2012 -1.6% 1/4/2013 9.3% 1/4/2014 -3.9% 1/4/2015 8.7% 1/4/2016 18.6% 1/4/2017 4.80% 1/4/2018 11.20%

1/5/2011 7.0% 1/5/2012 -10.9% 1/5/2013 10.9% 1/5/2014 0.1% 1/5/2015 8.4% 1/5/2016 23.2% 1/5/2017 -2.00% 1/5/2018 19.30%

1/6/2011 2.4% 1/6/2012 -15.9% 1/6/2013 -11.5% 1/6/2014 1.2% 1/6/2015 1.0% 1/6/2016 -3.4% 1/6/2017 3.40% 1/6/2018 17.40%

1/7/2011 -7.1% 1/7/2012 -11.8% 1/7/2013 2.6% 1/7/2014 5.2% 1/7/2015 -2.1% 1/7/2016 16.7% 1/7/2017 -6.70% 1/7/2018 12.10%

1/8/2011 -6.7% 1/8/2012 -5.9% 1/8/2013 9.1% 1/8/2014 -3.3% 1/8/2015 -9.3% 1/8/2016 10.6% 1/8/2017 1.70% 1/8/2018 8.50%

1/9/2011 -14.7% 1/9/2012 -2.5% 1/9/2013 6.0% 1/9/2014 -7.6% 1/9/2015 -20.0% 1/9/2016 5.3% 1/9/2017 3.40% 1/9/2018 2.90%

1/10/2011 -0.4% 1/10/2012 -8.7% 1/10/2013 -20.8% 1/10/2014 1.0% 1/10/2015 0.8% 1/10/2016 24.0% 1/10/2017 -2.90% 1/10/2018 9.90%

1/11/2011 8.3% 1/11/2012 4.1% 1/11/2013 -4.7% 1/11/2014 2.6% 1/11/2015 -13.0% 1/11/2016 14.7% 1/11/2017 -0.50% 1/11/2018 4.10%

1/12/2011 1.3% 1/12/2012 -9.5% 1/12/2013 -8.7% 1/12/2014 2.7% 1/12/2015 -8.1% 1/12/2016 -3.8% 1/12/2017 0.30% 1/12/2018 7.60%

1/13/2011 -1.0% 1/13/2012 4.5% 1/13/2013 -2.8% 1/13/2014 4.9% 1/13/2015 -12.3% 1/13/2016 -2.6% 1/13/2017 -1.00% 1/13/2018 -1.20%

1/14/2011 -7.1% 1/14/2012 14.4% 1/14/2013 4.5% 1/14/2014 5.7% 1/14/2015 -3.8% 1/14/2016 4.3% 1/14/2017 -7.30% 1/14/2018 6.50%

1/15/2011 -12.6% 1/15/2012 -2.6% 1/15/2013 8.1% 1/15/2014 2.5% 1/15/2015 2.6% 1/15/2016 3.5% 1/15/2017 -1.70% 1/15/2018 3.10%

1/16/2011 -12.9% 1/16/2012 -20.8% 1/16/2013 14.5% 1/16/2014 -2.6% 1/16/2015 -0.5% 1/16/2016 5.1% 1/16/2017 -8.40% 1/16/2018 11.90%

1/17/2011 -14.7% 1/17/2012 -7.1% 1/17/2013 9.9% 1/17/2014 -7.2% 1/17/2015 0.9% 1/17/2016 -0.2% 1/17/2017 -2.80% 1/17/2018 5.50%

1/18/2011 -22.4% 1/18/2012 8.9% 1/18/2013 3.7% 1/18/2014 3.6% 1/18/2015 -1.8% 1/18/2016 -2.4% 1/18/2017 -1.60% 1/18/2018 6.20%

1/19/2011 -18.1% 1/19/2012 7.1% 1/19/2013 -0.2% 1/19/2014 2.3% 1/19/2015 3.7% 1/19/2016 7.2% 1/19/2017 1.30% 1/19/2018 11.20%

1/20/2011 -20.4% 1/20/2012 -3.1% 1/20/2013 -0.4% 1/20/2014 8.1% 1/20/2015 -3.5% 1/20/2016 28.3% 1/20/2017 -16.10% 1/20/2018 3.90%

1/21/2011 0.7% 1/21/2012 -20.6% 1/21/2013 4.7% 1/21/2014 4.1% 1/21/2015 -16.9% 1/21/2016 3.4% 1/21/2017 -1.80% 1/21/2018 1.00%

1/22/2011 -4.3% 1/22/2012 1.2% 1/22/2013 8.5% 1/22/2014 -10.5% 1/22/2015 -4.1% 1/22/2016 -3.6% 1/22/2017 -17.60% 1/22/2018 -5.00%

1/23/2011 -14.3% 1/23/2012 -2.9% 1/23/2013 1.6% 1/23/2014 -1.8% 1/23/2015 0.3% 1/23/2016 7.9% 1/23/2017 -6.50% 1/23/2018 -12.90%

1/24/2011 3.1% 1/24/2012 8.5% 1/24/2013 -3.7% 1/24/2014 -8.6% 1/24/2015 -1.7% 1/24/2016 10.6% 1/24/2017 -4.50% 1/24/2018 -11.10%

1/25/2011 0.9% 1/25/2012 9.6% 1/25/2013 -9.6% 1/25/2014 -17.8% 1/25/2015 -4.7% 1/25/2016 0.9% 1/25/2017 -4.10% 1/25/2018 0.00%

1/26/2011 -2.5% 1/26/2012 2.8% 1/26/2013 -16.7% 1/26/2014 -3.7% 1/26/2015 -21.3% 1/26/2016 2.3% 1/26/2017 -5.90% 1/26/2018 -3.50%

1/27/2011 -6.0% 1/27/2012 -4.2% 1/27/2013 -35.5% 1/27/2014 -8.4% 1/27/2015 -32.6% 1/27/2016 -11.7% 1/27/2017 -13.00% 1/27/2018 -14.80%

1/28/2011 -8.0% 1/28/2012 -9.6% 1/28/2013 -1.7% 1/28/2014 -3.0% 1/28/2015 -14.1% 1/28/2016 -11.1% 1/28/2017 -8.60% 1/28/2018 -11.40%

1/29/2011 -10.7% 1/29/2012 1.9% 1/29/2013 5.5% 1/29/2014 0.5% 1/29/2015 -19.5% 1/29/2016 -5.8% 1/29/2017 3.50% 1/29/2018 11.90%

1/30/2011 -23.1% 1/30/2012 -1.4% 1/30/2013 10.0% 1/30/2014 -9.2% 1/30/2015 -29.8% 1/30/2016 -0.5% 1/30/2017 9.90% 1/30/2018 8.50%

1/31/2011 -12.2% 1/31/2012 -10.5% 1/31/2013 7.9% 1/31/2014 -32.1% 1/31/2015 -24.9% 1/31/2016 7.8% 1/31/2017 12.90% 1/31/2018 -2.10%

2/1/2011 -8.2% 2/1/2012 4.0% 2/1/2013 0.1% 2/1/2014 -5.8% 2/1/2015 -6.8% 2/1/2016 -0.8% 2/1/2017 -4.00% 2/1/2018 -8.60%

2/2/2011 -2.5% 2/2/2012 8.6% 2/2/2013 3.7% 2/2/2014 1.4% 2/2/2015 -6.9% 2/2/2016 -7.9% 2/2/2017 2.60% 2/2/2018 -5.20%

2/3/2011 3.5% 2/3/2012 8.4% 2/3/2013 -24.4% 2/3/2014 -8.1% 2/3/2015 -5.2% 2/3/2016 -7.1% 2/3/2017 -1.40% 2/3/2018 -9.00%

2/4/2011 6.1% 2/4/2012 8.4% 2/4/2013 -2.0% 2/4/2014 -6.7% 2/4/2015 -9.9% 2/4/2016 -12.6% 2/4/2017 2.90% 2/4/2018 -5.60%

2/5/2011 5.0% 2/5/2012 7.6% 2/5/2013 0.4% 2/5/2014 -6.5% 2/5/2015 -5.2% 2/5/2016 -13.3% 2/5/2017 -3.50% 2/5/2018 2.60%

2/6/2011 -7.4% 2/6/2012 13.8% 2/6/2013 -12.6% 2/6/2014 1.2% 2/6/2015 -19.3% 2/6/2016 -12.4% 2/6/2017 -8.40% 2/6/2018 2.00%

2/7/2011 -11.8% 2/7/2012 1.6% 2/7/2013 4.9% 2/7/2014 -6.2% 2/7/2015 -7.6% 2/7/2016 -14.3% 2/7/2017 1.60% 2/7/2018 -8.70%

2/8/2011 -25.1% 2/8/2012 -1.7% 2/8/2013 -1.3% 2/8/2014 0.7% 2/8/2015 -20.6% 2/8/2016 5.0% 2/8/2017 0.40% 2/8/2018 -4.30%

2/9/2011 -6.5% 2/9/2012 -8.9% 2/9/2013 2.2% 2/9/2014 3.0% 2/9/2015 -33.0% 2/9/2016 11.4% 2/9/2017 5.90% 2/9/2018 -3.40%

2/10/2011 -4.5% 2/10/2012 -18.0% 2/10/2013 4.8% 2/10/2014 -1.3% 2/10/2015 -7.1% 2/10/2016 11.9% 2/10/2017 9.30% 2/10/2018 18.60%

2/11/2011 1.9% 2/11/2012 -39.9% 2/11/2013 2.1% 2/11/2014 7.4% 2/11/2015 -10.7% 2/11/2016 11.4% 2/11/2017 3.30% 2/11/2018 0.20%

2/12/2011 2.0% 2/12/2012 -23.1% 2/12/2013 9.6% 2/12/2014 15.2% 2/12/2015 -17.2% 2/12/2016 8.3% 2/12/2017 -1.00% 2/12/2018 14.60%

2/13/2011 -0.3% 2/13/2012 -24.1% 2/13/2013 11.4% 2/13/2014 12.0% 2/13/2015 -20.4% 2/13/2016 -0.3% 2/13/2017 0.70% 2/13/2018 1.80%

Att U CEYap WorkpapersFig 2 data Page 27

2/14/2011 -11.8% 2/14/2012 -17.0% 2/14/2013 11.6% 2/14/2014 10.5% 2/14/2015 -13.1% 2/14/2016 3.7% 2/14/2017 2.90% 2/14/2018 3.20%

2/15/2011 -18.6% 2/15/2012 0.3% 2/15/2013 5.8% 2/15/2014 18.2% 2/15/2015 -13.5% 2/15/2016 16.8% 2/15/2017 3.20% 2/15/2018 6.40%

2/16/2011 -31.5% 2/16/2012 14.8% 2/16/2013 0.1% 2/16/2014 5.0% 2/16/2015 -9.2% 2/16/2016 25.6% 2/16/2017 12.20% 2/16/2018 -6.00%

2/17/2011 -4.2% 2/17/2012 13.9% 2/17/2013 -10.2% 2/17/2014 10.7% 2/17/2015 -22.1% 2/17/2016 9.5% 2/17/2017 -10.80% 2/17/2018 -11.00%

2/18/2011 5.6% 2/18/2012 1.0% 2/18/2013 -14.8% 2/18/2014 1.7% 2/18/2015 -11.2% 2/18/2016 40.4% 2/18/2017 -5.10% 2/18/2018 6.90%

2/19/2011 -19.3% 2/19/2012 -11.2% 2/19/2013 -8.5% 2/19/2014 1.0% 2/19/2015 -8.2% 2/19/2016 18.0% 2/19/2017 -0.60% 2/19/2018 0.90%

2/20/2011 -7.9% 2/20/2012 5.9% 2/20/2013 0.9% 2/20/2014 15.3% 2/20/2015 -13.6% 2/20/2016 8.9% 2/20/2017 1.50% 2/20/2018 1.00%

2/21/2011 0.3% 2/21/2012 12.5% 2/21/2013 4.5% 2/21/2014 1.8% 2/21/2015 -2.5% 2/21/2016 5.7% 2/21/2017 7.10% 2/21/2018 -3.40%

2/22/2011 -4.9% 2/22/2012 13.3% 2/22/2013 6.0% 2/22/2014 6.8% 2/22/2015 -12.4% 2/22/2016 0.6% 2/22/2017 10.50% 2/22/2018 -5.90%

2/23/2011 2.6% 2/23/2012 3.9% 2/23/2013 6.4% 2/23/2014 2.5% 2/23/2015 -16.3% 2/23/2016 7.7% 2/23/2017 2.00% 2/23/2018 -8.40%

2/24/2011 -3.2% 2/24/2012 6.5% 2/24/2013 -1.0% 2/24/2014 0.5% 2/24/2015 10.8% 2/24/2016 12.0% 2/24/2017 4.80% 2/24/2018 -4.70%

2/25/2011 1.0% 2/25/2012 -19.6% 2/25/2013 6.1% 2/25/2014 -17.0% 2/25/2015 12.3% 2/25/2016 9.0% 2/25/2017 5.10% 2/25/2018 -10.00%

2/26/2011 -28.2% 2/26/2012 -7.3% 2/26/2013 8.1% 2/26/2014 -9.4% 2/26/2015 8.1% 2/26/2016 10.2% 2/26/2017 1.00% 2/26/2018 -5.40%

2/27/2011 -4.5% 2/27/2012 -16.4% 2/27/2013 3.5% 2/27/2014 -15.5% 2/27/2015 8.4% 2/27/2016 7.4% 2/27/2017 -7.20% 2/27/2018 3.00%

2/28/2011 9.1% 2/28/2012 4.8% 2/28/2013 4.4% 2/28/2014 -12.8% 2/28/2015 -9.9% 2/28/2016 10.9% 2/28/2017 5.40% 2/28/2018 -0.30%

3/1/2011 18.3% 2/29/2012 0.1% 3/1/2013 11.1% 3/1/2014 -2.3% 3/1/2015 7.0% 2/29/2016 14.1% 3/1/2017 -13.80% 3/1/2018 -2.30%

3/2/2011 11.0% 3/1/2012 6.2% 3/2/2013 2.5% 3/2/2014 -3.6% 3/2/2015 7.7% 3/1/2016 2.4% 3/2/2017 -14.50% 3/2/2018 -7.00%

3/3/2011 -3.0% 3/2/2012 20.3% 3/3/2013 -17.2% 3/3/2014 0.3% 3/3/2015 8.6% 3/2/2016 4.8% 3/3/2017 -7.90% 3/3/2018 -1.30%

3/4/2011 6.5% 3/3/2012 29.8% 3/4/2013 -13.0% 3/4/2014 -3.7% 3/4/2015 10.3% 3/3/2016 9.8% 3/4/2017 -4.60% 3/4/2018 -3.30%

3/5/2011 12.4% 3/4/2012 24.1% 3/5/2013 1.8% 3/5/2014 -1.7% 3/5/2015 20.7% 3/4/2016 3.0% 3/5/2017 3.20% 3/5/2018 -16.00%

3/6/2011 2.3% 3/5/2012 15.8% 3/6/2013 -6.2% 3/6/2014 -16.9% 3/6/2015 24.4% 3/5/2016 -0.6% 3/6/2017 -6.70% 3/6/2018 -20.90%

3/7/2011 -6.9% 3/6/2012 -16.4% 3/7/2013 3.0% 3/7/2014 -16.4% 3/7/2015 22.0% 3/6/2016 34.1% 3/7/2017 -14.40% 3/7/2018 -20.70%

3/8/2011 6.4% 3/7/2012 5.3% 3/8/2013 6.4% 3/8/2014 8.6% 3/8/2015 12.3% 3/7/2016 14.7% 3/8/2017 -13.40% 3/8/2018 -14.40%

3/9/2011 10.9% 3/8/2012 18.0% 3/9/2013 4.5% 3/9/2014 -3.1% 3/9/2015 6.1% 3/8/2016 -5.0% 3/9/2017 4.70% 3/9/2018 -7.00%

3/10/2011 6.3% 3/9/2012 12.0% 3/10/2013 10.4% 3/10/2014 -5.6% 3/10/2015 14.7% 3/9/2016 -7.7% 3/10/2017 8.70% 3/10/2018 -5.50%

3/11/2011 -6.5% 3/10/2012 -7.5% 3/11/2013 14.9% 3/11/2014 -2.3% 3/11/2015 -0.4% 3/10/2016 -7.3% 3/11/2017 4.90% 3/11/2018 -5.80%

3/12/2011 -3.6% 3/11/2012 -27.7% 3/12/2013 15.0% 3/12/2014 1.2% 3/12/2015 0.5% 3/11/2016 8.3% 3/12/2017 9.90% 3/12/2018 -5.30%

3/13/2011 0.8% 3/12/2012 -15.4% 3/13/2013 1.7% 3/13/2014 -16.4% 3/13/2015 -6.4% 3/12/2016 0.1% 3/13/2017 17.40% 3/13/2018 2.50%

3/14/2011 5.2% 3/13/2012 -10.0% 3/14/2013 -2.1% 3/14/2014 -2.5% 3/14/2015 -5.5% 3/13/2016 0.1% 3/14/2017 17.10% 3/14/2018 8.10%

3/15/2011 3.1% 3/14/2012 -5.8% 3/15/2013 -3.1% 3/15/2014 5.8% 3/15/2015 -8.5% 3/14/2016 8.2% 3/15/2017 19.80% 3/15/2018 4.70%

3/16/2011 -4.3% 3/15/2012 -7.3% 3/16/2013 2.8% 3/16/2014 -0.4% 3/16/2015 -17.5% 3/15/2016 -8.0% 3/16/2017 16.30% 3/16/2018 -2.80%

3/17/2011 -19.9% 3/16/2012 0.8% 3/17/2013 -8.7% 3/17/2014 -6.9% 3/17/2015 -14.3% 3/16/2016 -4.4% 3/17/2017 10.10% 3/17/2018 0.90%

3/18/2011 -3.8% 3/17/2012 3.8% 3/18/2013 -3.2% 3/18/2014 -4.8% 3/18/2015 -6.7% 3/17/2016 3.1% 3/18/2017 12.40% 3/18/2018 -0.10%

3/19/2011 -9.8% 3/18/2012 -0.1% 3/19/2013 2.1% 3/19/2014 -1.2% 3/19/2015 -7.1% 3/18/2016 1.9% 3/19/2017 8.60% 3/19/2018 -6.90%

3/20/2011 7.3% 3/19/2012 -1.4% 3/20/2013 3.4% 3/20/2014 -3.8% 3/20/2015 -12.1% 3/19/2016 0.1% 3/20/2017 24.20% 3/20/2018 -7.90%

3/21/2011 3.7% 3/20/2012 4.9% 3/21/2013 -6.8% 3/21/2014 -12.0% 3/21/2015 -4.1% 3/20/2016 0.9% 3/21/2017 16.30% 3/21/2018 -11.40%

3/22/2011 -3.4% 3/21/2012 9.0% 3/22/2013 -9.2% 3/22/2014 -3.8% 3/22/2015 -6.6% 3/21/2016 8.9% 3/22/2017 20.20% 3/22/2018 -4.30%

3/23/2011 8.3% 3/22/2012 -5.8% 3/23/2013 -4.4% 3/23/2014 5.8% 3/23/2015 -6.9% 3/22/2016 16.5% 3/23/2017 9.20% 3/23/2018 5.40%

3/24/2011 8.1% 3/23/2012 -15.8% 3/24/2013 -10.1% 3/24/2014 4.3% 3/24/2015 -2.7% 3/23/2016 -3.7% 3/24/2017 12.60% 3/24/2018 -1.50%

3/25/2011 1.1% 3/24/2012 -9.5% 3/25/2013 -3.4% 3/25/2014 1.6% 3/25/2015 -4.8% 3/24/2016 -9.3% 3/25/2017 11.90% 3/25/2018 2.80%

3/26/2011 4.6% 3/25/2012 6.0% 3/26/2013 -7.4% 3/26/2014 -3.7% 3/26/2015 -14.9% 3/25/2016 -5.1% 3/26/2017 6.60% 3/26/2018 -4.90%

3/27/2011 -4.5% 3/26/2012 -5.5% 3/27/2013 1.7% 3/27/2014 2.3% 3/27/2015 -16.7% 3/26/2016 -3.4% 3/27/2017 4.20% 3/27/2018 -12.80%

3/28/2011 3.9% 3/27/2012 0.6% 3/28/2013 6.9% 3/28/2014 7.5% 3/28/2015 -6.4% 3/27/2016 0.8% 3/28/2017 -5.00% 3/28/2018 -5.30%

3/29/2011 9.3% 3/28/2012 -1.9% 3/29/2013 25.8% 3/29/2014 13.3% 3/29/2015 -10.8% 3/28/2016 43.8% 3/29/2017 -0.90% 3/29/2018 -3.80%

3/30/2011 2.3% 3/29/2012 -1.2% 3/30/2013 7.0% 3/30/2014 -8.3% 3/30/2015 -16.2% 3/29/2016 3.9% 3/30/2017 6.00% 3/30/2018 0.70%

3/31/2011 -15.9% 3/30/2012 -4.6% 3/31/2013 0.0% 3/31/2014 -0.8% 3/31/2015 -7.7% 3/30/2016 10.9% 3/31/2017 5.40% 3/31/2018 -4.00%


4/1/2011 -9.2% 3/31/2012 -1.5% 4/1/2013 3.1% 4/1/2014 -11.4% 4/1/2015 4.0% 3/31/2016 -2.7% 4/1/2017 -10.90% 4/1/2018 -3.30%

4/2/2011 -3.3% 4/1/2012 6.3% 4/2/2013 8.1% 4/2/2014 -5.6% 4/2/2015 11.2% 4/1/2016 -7.8% 4/2/2017 -1.30% 4/2/2018 -4.20%

4/3/2011 -11.5% 4/2/2012 17.0% 4/3/2013 8.6% 4/3/2014 6.1% 4/3/2015 5.9% 4/2/2016 -12.9% 4/3/2017 12.30% 4/3/2018 -10.50%

4/4/2011 7.3% 4/3/2012 11.7% 4/4/2013 4.3% 4/4/2014 -1.0% 4/4/2015 12.7% 4/3/2016 -2.9% 4/4/2017 -5.10% 4/4/2018 -12.50%

4/5/2011 1.4% 4/4/2012 -0.8% 4/5/2013 2.1% 4/5/2014 4.7% 4/5/2015 -6.8% 4/4/2016 -1.1% 4/5/2017 0.90% 4/5/2018 -7.60%

4/6/2011 -16.9% 4/5/2012 -10.2% 4/6/2013 6.0% 4/6/2014 10.7% 4/6/2015 -10.6% 4/5/2016 -0.5% 4/6/2017 -0.10% 4/6/2018 -9.40%

4/7/2011 -25.3% 4/6/2012 10.1% 4/7/2013 4.5% 4/7/2014 0.9% 4/7/2015 -10.6% 4/6/2016 3.8% 4/7/2017 3.10% 4/7/2018 -7.60%

4/8/2011 -5.0% 4/7/2012 19.8% 4/8/2013 -7.1% 4/8/2014 -13.7% 4/8/2015 5.8% 4/7/2016 -3.3% 4/8/2017 10.10% 4/8/2018 -5.30%

4/9/2011 4.6% 4/8/2012 9.0% 4/9/2013 9.4% 4/9/2014 -14.4% 4/9/2015 13.4% 4/8/2016 1.5% 4/9/2017 -0.10% 4/9/2018 -6.70%

4/10/2011 2.6% 4/9/2012 5.1% 4/10/2013 8.8% 4/10/2014 -7.7% 4/10/2015 6.6% 4/9/2016 -1.3% 4/10/2017 -3.30% 4/10/2018 12.70%

4/11/2011 12.2% 4/10/2012 -6.7% 4/11/2013 7.1% 4/11/2014 -10.9% 4/11/2015 12.6% 4/10/2016 5.6% 4/11/2017 -0.40% 4/11/2018 -0.60%

4/12/2011 0.7% 4/11/2012 -10.6% 4/12/2013 1.3% 4/12/2014 -20.6% 4/12/2015 7.2% 4/11/2016 5.6% 4/12/2017 2.30% 4/12/2018 0.40%

4/13/2011 -10.0% 4/12/2012 -6.6% 4/13/2013 10.5% 4/13/2014 -21.0% 4/13/2015 6.4% 4/12/2016 -2.4% 4/13/2017 12.40% 4/13/2018 -13.60%

4/14/2011 10.2% 4/13/2012 4.2% 4/14/2013 10.1% 4/14/2014 -3.8% 4/14/2015 4.8% 4/13/2016 1.8% 4/14/2017 5.20% 4/14/2018 -7.80%

4/15/2011 7.2% 4/14/2012 5.5% 4/15/2013 -1.7% 4/15/2014 -6.8% 4/15/2015 8.1% 4/14/2016 0.6% 4/15/2017 -6.80% 4/15/2018 -1.00%

4/16/2011 -3.9% 4/15/2012 7.8% 4/16/2013 3.0% 4/16/2014 -7.1% 4/16/2015 7.6% 4/15/2016 -6.2% 4/16/2017 -1.70% 4/16/2018 11.20%

4/17/2011 -7.2% 4/16/2012 11.7% 4/17/2013 15.7% 4/17/2014 -2.1% 4/17/2015 6.1% 4/16/2016 -5.3% 4/17/2017 1.20% 4/17/2018 -5.10%

4/18/2011 -7.0% 4/17/2012 9.3% 4/18/2013 16.0% 4/18/2014 -20.5% 4/18/2015 3.5% 4/17/2016 4.1% 4/18/2017 4.40% 4/18/2018 -5.50%

4/19/2011 -1.0% 4/18/2012 2.9% 4/19/2013 9.4% 4/19/2014 -0.6% 4/19/2015 2.9% 4/18/2016 8.6% 4/19/2017 2.90% 4/19/2018 1.60%

4/20/2011 -5.8% 4/19/2012 -6.8% 4/20/2013 2.2% 4/20/2014 -7.4% 4/20/2015 2.4% 4/19/2016 9.8% 4/20/2017 5.20% 4/20/2018 -14.20%

4/21/2011 -3.3% 4/20/2012 -10.8% 4/21/2013 -4.1% 4/21/2014 -12.0% 4/21/2015 -2.7% 4/20/2016 6.8% 4/21/2017 6.40% 4/21/2018 -7.80%

4/22/2011 -4.8% 4/21/2012 -8.8% 4/22/2013 -0.5% 4/22/2014 -12.4% 4/22/2015 2.6% 4/21/2016 2.9% 4/22/2017 12.20% 4/22/2018 2.00%

4/23/2011 -2.4% 4/22/2012 -8.1% 4/23/2013 0.4% 4/23/2014 3.4% 4/23/2015 2.0% 4/22/2016 3.2% 4/23/2017 11.80% 4/23/2018 -0.10%

4/24/2011 -9.0% 4/23/2012 -5.8% 4/24/2013 -0.9% 4/24/2014 3.2% 4/24/2015 2.8% 4/23/2016 0.7% 4/24/2017 7.60% 4/24/2018 -10.30%

4/25/2011 2.6% 4/24/2012 -6.8% 4/25/2013 -6.7% 4/25/2014 -6.2% 4/25/2015 5.7% 4/24/2016 3.0% 4/25/2017 2.30% 4/25/2018 3.60%

4/26/2011 2.1% 4/25/2012 -6.9% 4/26/2013 -6.5% 4/26/2014 -6.6% 4/26/2015 11.2% 4/25/2016 11.7% 4/26/2017 5.20% 4/26/2018 3.70%

4/27/2011 0.6% 4/26/2012 -16.4% 4/27/2013 -2.3% 4/27/2014 -0.6% 4/27/2015 3.0% 4/26/2016 -2.0% 4/27/2017 7.10% 4/27/2018 5.30%

4/28/2011 -3.2% 4/27/2012 -5.9% 4/28/2013 -7.5% 4/28/2014 2.7% 4/28/2015 -2.3% 4/27/2016 -0.6% 4/28/2017 5.20% 4/28/2018 -0.60%

4/29/2011 -11.3% 4/28/2012 -1.8% 4/29/2013 -7.4% 4/29/2014 -9.9% 4/29/2015 -14.5% 4/28/2016 2.0% 4/29/2017 5.40% 4/29/2018 12.70%

4/30/2011 1.0% 4/29/2012 -5.8% 4/30/2013 -10.0% 4/30/2014 -17.2% 4/30/2015 -13.8% 4/29/2016 -3.0% 4/30/2017 10.00% 4/30/2018 0.70%

5/1/2011 4.0% 4/30/2012 -6.1% 5/1/2013 6.3% 5/1/2014 -9.6% 5/1/2015 -0.3% 4/30/2016 3.8% 5/1/2017 6.50%

5/2/2011 2.5% 5/1/2012 -2.3% 5/2/2013 -3.7% 5/2/2014 -8.6% 5/2/2015 -2.6% 5/1/2016 -7.8% 5/2/2017 1.50%

5/3/2011 -8.3% 5/2/2012 -1.7% 5/3/2013 -5.3% 5/3/2014 -12.0% 5/3/2015 0.7% 5/2/2016 -10.9% 5/3/2017 12.40%

5/4/2011 -11.0% 5/3/2012 -5.1% 5/4/2013 0.3% 5/4/2014 -4.0% 5/4/2015 4.6% 5/3/2016 -6.3% 5/4/2017 6.60%

5/5/2011 -3.0% 5/4/2012 3.3% 5/5/2013 0.8% 5/5/2014 -6.6% 5/5/2015 0.2% 5/4/2016 -3.2% 5/5/2017 -0.10%

5/6/2011 -10.3% 5/5/2012 1.7% 5/6/2013 5.3% 5/6/2014 -8.5% 5/6/2015 0.5% 5/5/2016 2.6% 5/6/2017 12.70%

5/7/2011 4.0% 5/6/2012 -2.6% 5/7/2013 1.2% 5/7/2014 2.9% 5/7/2015 -8.6% 5/6/2016 -1.9% 5/7/2017 9.10%

5/8/2011 -19.0% 5/7/2012 -9.3% 5/8/2013 5.3% 5/8/2014 3.7% 5/8/2015 5.9% 5/7/2016 -4.6% 5/8/2017 -8.40%

5/9/2011 -4.3% 5/8/2012 -7.1% 5/9/2013 7.8% 5/9/2014 5.7% 5/9/2015 7.9% 5/8/2016 -7.0% 5/9/2017 0.90%

5/10/2011 -1.2% 5/9/2012 -9.2% 5/10/2013 3.7% 5/10/2014 4.6% 5/10/2015 12.4% 5/9/2016 -12.9% 5/10/2017 -6.80%

5/11/2011 4.9% 5/10/2012 -14.6% 5/11/2013 -1.0% 5/11/2014 4.5% 5/11/2015 7.5% 5/10/2016 -12.5% 5/11/2017 -9.40%

5/12/2011 -0.8% 5/11/2012 -10.0% 5/12/2013 -8.5% 5/12/2014 -3.7% 5/12/2015 2.7% 5/11/2016 -10.1% 5/12/2017 -6.90%

5/13/2011 -2.8% 5/12/2012 -7.1% 5/13/2013 -15.9% 5/13/2014 -8.4% 5/13/2015 2.6% 5/12/2016 -3.0% 5/13/2017 -8.20%

5/14/2011 -16.5% 5/13/2012 -9.2% 5/14/2013 -8.8% 5/14/2014 -14.7% 5/14/2015 0.9% 5/13/2016 -3.5% 5/14/2017 -0.90%

5/15/2011 -18.4% 5/14/2012 -8.3% 5/15/2013 -6.3% 5/15/2014 -23.8% 5/15/2015 4.3% 5/14/2016 -2.5% 5/15/2017 4.40%

5/16/2011 -3.1% 5/15/2012 -3.3% 5/16/2013 -2.2% 5/16/2014 -12.1% 5/16/2015 13.4% 5/15/2016 -4.2% 5/16/2017 -5.70%


5/17/2011 1.1% 5/16/2012 -13.9% 5/17/2013 2.2% 5/17/2014 -14.4% 5/17/2015 -0.6% 5/16/2016 -5.1% 5/17/2017 -7.90%

5/18/2011 -0.1% 5/17/2012 -14.0% 5/18/2013 3.0% 5/18/2014 -12.5% 5/18/2015 -6.3% 5/17/2016 -7.0% 5/18/2017 -13.10%

5/19/2011 7.9% 5/18/2012 -9.3% 5/19/2013 8.0% 5/19/2014 -6.9% 5/19/2015 4.5% 5/18/2016 -2.8% 5/19/2017 2.30%

5/20/2011 7.2% 5/19/2012 -7.2% 5/20/2013 -1.9% 5/20/2014 -7.8% 5/20/2015 0.5% 5/19/2016 -4.9% 5/20/2017 4.70%

5/21/2011 7.4% 5/20/2012 -18.1% 5/21/2013 -5.5% 5/21/2014 4.1% 5/21/2015 1.1% 5/20/2016 12.5% 5/21/2017 13.00%

5/22/2011 -0.3% 5/21/2012 -15.1% 5/22/2013 1.2% 5/22/2014 4.5% 5/22/2015 5.0% 5/21/2016 11.7% 5/22/2017 8.50%

5/23/2011 -9.8% 5/22/2012 -6.2% 5/23/2013 2.3% 5/23/2014 -0.7% 5/23/2015 -0.6% 5/22/2016 -0.6% 5/23/2017 7.60%

5/24/2011 4.2% 5/23/2012 -0.8% 5/24/2013 8.6% 5/24/2014 2.7% 5/24/2015 3.4% 5/23/2016 -1.9% 5/24/2017 0.40%

5/25/2011 3.7% 5/24/2012 7.3% 5/25/2013 8.5% 5/25/2014 -7.9% 5/25/2015 11.6% 5/24/2016 6.3% 5/25/2017 -3.60%

5/26/2011 -0.3% 5/25/2012 -6.8% 5/26/2013 8.0% 5/26/2014 -7.5% 5/26/2015 9.4% 5/25/2016 -3.0% 5/26/2017 0.10%

5/27/2011 -1.7% 5/26/2012 -1.7% 5/27/2013 3.3% 5/27/2014 -14.8% 5/27/2015 2.7% 5/26/2016 -7.1% 5/27/2017 -5.40%

5/28/2011 -2.3% 5/27/2012 11.7% 5/28/2013 -3.6% 5/28/2014 -9.1% 5/28/2015 0.7% 5/27/2016 -1.0% 5/28/2017 2.70%

5/29/2011 -16.0% 5/28/2012 5.3% 5/29/2013 -1.9% 5/29/2014 -10.5% 5/29/2015 -11.4% 5/28/2016 -1.6% 5/29/2017 -1.60%

5/30/2011 5.7% 5/29/2012 3.6% 5/30/2013 -2.5% 5/30/2014 -9.6% 5/30/2015 -9.1% 5/29/2016 1.9% 5/30/2017 -1.40%

5/31/2011 0.4% 5/30/2012 4.8% 5/31/2013 -5.1% 5/31/2014 -7.0% 5/31/2015 -8.8% 5/30/2016 -4.4% 5/31/2017 -3.30%

6/1/2011 3.0% 5/31/2012 -0.6% 6/1/2013 0.4% 6/1/2014 -7.2% 6/1/2015 -6.0% 5/31/2016 6.8% 6/1/2017 -11.70%

6/2/2011 8.6% 6/1/2012 -8.1% 6/2/2013 0.8% 6/2/2014 -3.9% 6/2/2015 -1.0% 6/1/2016 -11.0% 6/2/2017 -3.40%

6/3/2011 6.7% 6/2/2012 -1.6% 6/3/2013 3.3% 6/3/2014 -0.4% 6/3/2015 -2.4% 6/2/2016 -5.3% 6/3/2017 -5.80%

6/4/2011 10.0% 6/3/2012 -0.8% 6/4/2013 -0.9% 6/4/2014 3.1% 6/4/2015 -3.2% 6/3/2016 3.3% 6/4/2017 -1.30%

6/5/2011 1.2% 6/4/2012 0.5% 6/5/2013 5.5% 6/5/2014 -0.4% 6/5/2015 1.0% 6/4/2016 -3.2% 6/5/2017 -4.30%

6/6/2011 -1.0% 6/5/2012 -2.6% 6/6/2013 5.4% 6/6/2014 3.5% 6/6/2015 -1.2% 6/5/2016 1.6% 6/6/2017 -9.10%

6/7/2011 6.9% 6/6/2012 4.7% 6/7/2013 3.3% 6/7/2014 3.1% 6/7/2015 -9.7% 6/6/2016 -5.7% 6/7/2017 -11.80%

6/8/2011 8.1% 6/7/2012 -1.1% 6/8/2013 3.9% 6/8/2014 1.5% 6/8/2015 -14.2% 6/7/2016 -4.3% 6/8/2017 -10.70%

6/9/2011 7.5% 6/8/2012 -1.9% 6/9/2013 2.3% 6/9/2014 -0.4% 6/9/2015 -15.5% 6/8/2016 -6.0% 6/9/2017 -6.50%

6/10/2011 9.7% 6/9/2012 0.0% 6/10/2013 0.5% 6/10/2014 -0.2% 6/10/2015 -9.5% 6/9/2016 -5.6% 6/10/2017 -5.90%

6/11/2011 7.9% 6/10/2012 -1.5% 6/11/2013 0.1% 6/11/2014 4.3% 6/11/2015 -3.0% 6/10/2016 -3.4% 6/11/2017 -6.60%

6/12/2011 10.3% 6/11/2012 -1.1% 6/12/2013 4.3% 6/12/2014 -4.2% 6/12/2015 -6.3% 6/11/2016 -11.5% 6/12/2017 -9.70%

6/13/2011 7.8% 6/12/2012 -3.9% 6/13/2013 -0.2% 6/13/2014 -25.2% 6/13/2015 -7.5% 6/12/2016 -3.6% 6/13/2017 -4.50%

6/14/2011 3.9% 6/13/2012 -0.6% 6/14/2013 3.4% 6/14/2014 -5.2% 6/14/2015 -5.9% 6/13/2016 -9.5% 6/14/2017 -5.80%

6/15/2011 5.1% 6/14/2012 2.3% 6/15/2013 3.5% 6/15/2014 -2.4% 6/15/2015 -12.7% 6/14/2016 -11.2% 6/15/2017 4.40%

6/16/2011 9.0% 6/15/2012 3.2% 6/16/2013 -1.9% 6/16/2014 0.7% 6/16/2015 -13.7% 6/15/2016 -8.3% 6/16/2017 4.70%

6/17/2011 5.6% 6/16/2012 -0.5% 6/17/2013 -2.6% 6/17/2014 1.6% 6/17/2015 -14.5% 6/16/2016 -7.4% 6/17/2017 1.30%

6/18/2011 6.4% 6/17/2012 -6.6% 6/18/2013 0.5% 6/18/2014 3.5% 6/18/2015 -12.0% 6/17/2016 -0.1% 6/18/2017 7.10%

6/19/2011 8.5% 6/18/2012 -5.8% 6/19/2013 1.0% 6/19/2014 1.9% 6/19/2015 -17.0% 6/18/2016 0.7% 6/19/2017 19.70%

6/20/2011 2.7% 6/19/2012 -7.2% 6/20/2013 -1.2% 6/20/2014 -0.7% 6/20/2015 -15.8% 6/19/2016 4.9% 6/20/2017 11.90%

6/21/2011 -0.6% 6/20/2012 -1.7% 6/21/2013 -2.8% 6/21/2014 -1.2% 6/21/2015 -17.3% 6/20/2016 16.1% 6/21/2017 18.10%

6/22/2011 1.8% 6/21/2012 -3.1% 6/22/2013 -1.6% 6/22/2014 -6.0% 6/22/2015 -15.1% 6/21/2016 9.6% 6/22/2017 3.70%

6/23/2011 -0.6% 6/22/2012 -3.2% 6/23/2013 -3.6% 6/23/2014 -6.1% 6/23/2015 -6.7% 6/22/2016 8.6% 6/23/2017 9.30%

6/24/2011 -3.3% 6/23/2012 -2.4% 6/24/2013 2.4% 6/24/2014 -1.9% 6/24/2015 -6.7% 6/23/2016 11.1% 6/24/2017 3.40%

6/25/2011 -6.2% 6/24/2012 -8.5% 6/25/2013 -1.4% 6/25/2014 -6.2% 6/25/2015 -9.5% 6/24/2016 8.5% 6/25/2017 15.50%

6/26/2011 -8.7% 6/25/2012 -3.6% 6/26/2013 -8.1% 6/26/2014 -1.8% 6/26/2015 -13.9% 6/25/2016 10.9% 6/26/2017 19.70%

6/27/2011 -11.6% 6/26/2012 -7.0% 6/27/2013 -9.7% 6/27/2014 -5.1% 6/27/2015 0.7% 6/26/2016 19.2% 6/27/2017 5.40%

6/28/2011 -8.7% 6/27/2012 -8.6% 6/28/2013 -16.9% 6/28/2014 -3.0% 6/28/2015 -5.1% 6/27/2016 14.6% 6/28/2017 6.20%

6/29/2011 -4.3% 6/28/2012 -11.1% 6/29/2013 -27.4% 6/29/2014 -10.2% 6/29/2015 -17.0% 6/28/2016 16.8% 6/29/2017 6.60%

6/30/2011 -9.4% 6/29/2012 -9.7% 6/30/2013 -20.8% 6/30/2014 -5.5% 6/30/2015 -16.1% 6/29/2016 14.7% 6/30/2017 5.10%

7/1/2011 4.0% 6/30/2012 -13.5% 7/1/2013 -12.9% 7/1/2014 2.0% 7/1/2015 3.4% 6/30/2016 3.4% 7/1/2017 -9.90%


7/2/2011 2.1% 7/1/2012 4.6% 7/2/2013 -4.0% 7/2/2014 -3.2% 7/2/2015 6.1% 7/1/2016 -3.1% 7/2/2017 -1.90%

7/3/2011 -5.6% 7/2/2012 5.6% 7/3/2013 3.2% 7/3/2014 -0.8% 7/3/2015 4.3% 7/2/2016 -1.8% 7/3/2017 -0.30%

7/4/2011 -11.2% 7/3/2012 7.0% 7/4/2013 -6.3% 7/4/2014 -3.0% 7/4/2015 1.5% 7/3/2016 -0.2% 7/4/2017 0.20%

7/5/2011 -6.5% 7/4/2012 3.2% 7/5/2013 1.9% 7/5/2014 -5.4% 7/5/2015 4.5% 7/4/2016 1.1% 7/5/2017 7.00%

7/6/2011 -13.3% 7/5/2012 6.2% 7/6/2013 5.7% 7/6/2014 -9.8% 7/6/2015 8.2% 7/5/2016 -1.8% 7/6/2017 3.30%

7/7/2011 -9.6% 7/6/2012 2.6% 7/7/2013 2.8% 7/7/2014 -6.5% 7/7/2015 3.7% 7/6/2016 -8.0% 7/7/2017 0.90%

7/8/2011 -4.7% 7/7/2012 12.3% 7/8/2013 4.8% 7/8/2014 -2.0% 7/8/2015 9.2% 7/7/2016 -6.8% 7/8/2017 8.10%

7/9/2011 -0.6% 7/8/2012 3.1% 7/9/2013 -4.3% 7/9/2014 -2.6% 7/9/2015 8.6% 7/8/2016 -2.2% 7/9/2017 14.10%

7/10/2011 -4.7% 7/9/2012 2.6% 7/10/2013 2.1% 7/10/2014 3.8% 7/10/2015 10.4% 7/9/2016 -4.0% 7/10/2017 10.90%

7/11/2011 0.7% 7/10/2012 -5.8% 7/11/2013 3.2% 7/11/2014 6.0% 7/11/2015 15.8% 7/10/2016 3.5% 7/11/2017 0.60%

7/12/2011 4.9% 7/11/2012 -5.6% 7/12/2013 -0.7% 7/12/2014 2.3% 7/12/2015 2.4% 7/11/2016 -2.5% 7/12/2017 1.10%

7/13/2011 5.9% 7/12/2012 3.8% 7/13/2013 2.8% 7/13/2014 -5.1% 7/13/2015 0.6% 7/12/2016 -2.8% 7/13/2017 3.10%

7/14/2011 6.6% 7/13/2012 1.2% 7/14/2013 -4.1% 7/14/2014 -1.3% 7/14/2015 -5.1% 7/13/2016 -4.0% 7/14/2017 0.40%

7/15/2011 6.2% 7/14/2012 4.9% 7/15/2013 0.2% 7/15/2014 4.8% 7/15/2015 4.8% 7/14/2016 -1.6% 7/15/2017 5.40%

7/16/2011 6.4% 7/15/2012 -0.8% 7/16/2013 4.5% 7/16/2014 8.1% 7/16/2015 -1.9% 7/15/2016 -1.2% 7/16/2017 6.40%

7/17/2011 3.6% 7/16/2012 4.1% 7/17/2013 12.8% 7/17/2014 11.3% 7/17/2015 -0.7% 7/16/2016 0.1% 7/17/2017 -0.30%

7/18/2011 -4.9% 7/17/2012 4.4% 7/18/2013 5.6% 7/18/2014 19.0% 7/18/2015 1.4% 7/17/2016 5.6% 7/18/2017 1.50%

7/19/2011 -9.2% 7/18/2012 -0.3% 7/19/2013 4.8% 7/19/2014 15.1% 7/19/2015 -4.2% 7/18/2016 2.9% 7/19/2017 -1.80%

7/20/2011 -2.0% 7/19/2012 -3.4% 7/20/2013 10.0% 7/20/2014 9.3% 7/20/2015 -0.2% 7/19/2016 -5.6% 7/20/2017 6.00%

7/21/2011 -2.0% 7/20/2012 -11.1% 7/21/2013 8.7% 7/21/2014 9.3% 7/21/2015 -4.7% 7/20/2016 1.4% 7/21/2017 -2.00%

7/22/2011 1.3% 7/21/2012 -3.5% 7/22/2013 4.5% 7/22/2014 9.3% 7/22/2015 1.4% 7/21/2016 6.4% 7/22/2017 2.00%

7/23/2011 0.4% 7/22/2012 -7.7% 7/23/2013 7.0% 7/23/2014 1.6% 7/23/2015 1.1% 7/22/2016 21.6% 7/23/2017 7.20%

7/24/2011 1.8% 7/23/2012 -6.6% 7/24/2013 6.1% 7/24/2014 0.0% 7/24/2015 -0.2% 7/23/2016 9.6% 7/24/2017 0.10%

7/25/2011 -7.0% 7/24/2012 -0.2% 7/25/2013 4.4% 7/25/2014 -2.6% 7/25/2015 -3.2% 7/24/2016 16.3% 7/25/2017 1.10%

7/26/2011 -3.3% 7/25/2012 -0.6% 7/26/2013 7.1% 7/26/2014 5.3% 7/26/2015 -1.4% 7/25/2016 4.6% 7/26/2017 1.20%

7/27/2011 -3.5% 7/26/2012 -0.6% 7/27/2013 8.7% 7/27/2014 -1.9% 7/27/2015 -1.4% 7/26/2016 5.5% 7/27/2017 -1.70%

7/28/2011 -1.0% 7/27/2012 -2.3% 7/28/2013 7.9% 7/28/2014 -0.8% 7/28/2015 -1.1% 7/27/2016 10.2% 7/28/2017 -2.70%

7/29/2011 -4.1% 7/28/2012 1.6% 7/29/2013 9.9% 7/29/2014 -2.3% 7/29/2015 -13.1% 7/28/2016 22.6% 7/29/2017 -0.50%

7/30/2011 6.5% 7/29/2012 -0.7% 7/30/2013 10.8% 7/30/2014 -1.5% 7/30/2015 -13.1% 7/29/2016 26.6% 7/30/2017 2.00%

7/31/2011 -4.0% 7/30/2012 -5.3% 7/31/2013 15.3% 7/31/2014 -3.9% 7/31/2015 -6.4% 7/30/2016 23.2% 7/31/2017 0.00%

8/1/2011 -2.8% 7/31/2012 -1.2% 8/1/2013 17.5% 8/1/2014 -1.8% 8/1/2015 -6.7% 7/31/2016 24.1% 8/1/2017 1.50%

8/2/2011 -3.3% 8/1/2012 2.7% 8/2/2013 14.8% 8/2/2014 2.3% 8/2/2015 -5.1% 8/1/2016 13.6% 8/2/2017 7.40%

8/3/2011 -1.9% 8/2/2012 0.1% 8/3/2013 18.7% 8/3/2014 -0.5% 8/3/2015 -2.6% 8/2/2016 5.8% 8/3/2017 7.30%

8/4/2011 -1.0% 8/3/2012 -0.9% 8/4/2013 15.4% 8/4/2014 4.0% 8/4/2015 -6.7% 8/3/2016 9.1% 8/4/2017 0.60%

8/5/2011 4.9% 8/4/2012 5.7% 8/5/2013 14.9% 8/5/2014 3.7% 8/5/2015 -8.1% 8/4/2016 5.3% 8/5/2017 4.30%

8/6/2011 3.8% 8/5/2012 0.6% 8/6/2013 11.5% 8/6/2014 10.1% 8/6/2015 -10.9% 8/5/2016 7.3% 8/6/2017 6.40%

8/7/2011 2.7% 8/6/2012 -3.9% 8/7/2013 13.5% 8/7/2014 4.8% 8/7/2015 -4.0% 8/6/2016 6.1% 8/7/2017 2.60%

8/8/2011 5.2% 8/7/2012 -13.2% 8/8/2013 15.2% 8/8/2014 6.1% 8/8/2015 -4.1% 8/7/2016 9.0% 8/8/2017 4.10%

8/9/2011 -5.2% 8/8/2012 -3.5% 8/9/2013 15.7% 8/9/2014 6.4% 8/9/2015 -7.1% 8/8/2016 5.6% 8/9/2017 6.20%

8/10/2011 1.8% 8/9/2012 -16.3% 8/10/2013 17.4% 8/10/2014 4.1% 8/10/2015 -1.9% 8/9/2016 1.8% 8/10/2017 0.80%

8/11/2011 6.5% 8/10/2012 -16.3% 8/11/2013 11.8% 8/11/2014 -0.8% 8/11/2015 3.4% 8/10/2016 0.2% 8/11/2017 3.00%

8/12/2011 1.5% 8/11/2012 -14.7% 8/12/2013 12.8% 8/12/2014 2.7% 8/12/2015 -0.2% 8/11/2016 3.0% 8/12/2017 -0.60%

8/13/2011 4.2% 8/12/2012 -21.0% 8/13/2013 10.8% 8/13/2014 4.1% 8/13/2015 -10.0% 8/12/2016 3.6% 8/13/2017 4.80%

8/14/2011 2.8% 8/13/2012 -20.0% 8/14/2013 10.4% 8/14/2014 4.4% 8/14/2015 -11.0% 8/13/2016 11.5% 8/14/2017 -3.60%

8/15/2011 -1.5% 8/14/2012 -15.8% 8/15/2013 8.2% 8/15/2014 3.6% 8/15/2015 -10.2% 8/14/2016 13.6% 8/15/2017 -2.30%

8/16/2011 0.1% 8/15/2012 -12.8% 8/16/2013 5.0% 8/16/2014 3.9% 8/16/2015 -22.6% 8/15/2016 15.1% 8/16/2017 -5.90%


8/17/2011 -1.5% 8/16/2012 -18.1% 8/17/2013 12.2% 8/17/2014 -2.8% 8/17/2015 -10.0% 8/16/2016 7.3% 8/17/2017 -2.40%

8/18/2011 -1.2% 8/17/2012 -15.7% 8/18/2013 7.8% 8/18/2014 3.2% 8/18/2015 -5.9% 8/17/2016 2.0% 8/18/2017 -1.10%

8/19/2011 1.6% 8/18/2012 -14.1% 8/19/2013 10.6% 8/19/2014 5.6% 8/19/2015 -4.0% 8/18/2016 5.3% 8/19/2017 -5.10%

8/20/2011 7.5% 8/19/2012 -10.5% 8/20/2013 5.2% 8/20/2014 8.6% 8/20/2015 2.9% 8/19/2016 1.0% 8/20/2017 -0.60%

8/21/2011 3.5% 8/20/2012 -11.3% 8/21/2013 7.9% 8/21/2014 1.5% 8/21/2015 5.5% 8/20/2016 2.6% 8/21/2017 0.10%

8/22/2011 2.3% 8/21/2012 6.8% 8/22/2013 5.6% 8/22/2014 5.2% 8/22/2015 4.6% 8/21/2016 6.6% 8/22/2017 -7.90%

8/23/2011 -4.1% 8/22/2012 5.7% 8/23/2013 6.3% 8/23/2014 12.0% 8/23/2015 -0.4% 8/22/2016 -0.3% 8/23/2017 -0.90%

8/24/2011 -5.0% 8/23/2012 10.6% 8/24/2013 9.7% 8/24/2014 7.0% 8/24/2015 -0.7% 8/23/2016 2.5% 8/24/2017 -2.70%

8/25/2011 -6.9% 8/24/2012 11.2% 8/25/2013 13.0% 8/25/2014 10.0% 8/25/2015 -5.7% 8/24/2016 -1.0% 8/25/2017 -2.60%

8/26/2011 -9.1% 8/25/2012 11.9% 8/26/2013 3.1% 8/26/2014 11.7% 8/26/2015 -9.4% 8/25/2016 -0.6% 8/26/2017 -1.50%

8/27/2011 -7.2% 8/26/2012 17.4% 8/27/2013 4.6% 8/27/2014 8.1% 8/27/2015 -4.7% 8/26/2016 -6.2% 8/27/2017 5.40%

8/28/2011 -11.2% 8/27/2012 11.2% 8/28/2013 -6.1% 8/28/2014 3.5% 8/28/2015 -9.3% 8/27/2016 -5.8% 8/28/2017 7.80%

8/29/2011 -4.0% 8/28/2012 5.0% 8/29/2013 -2.3% 8/29/2014 -1.0% 8/29/2015 -2.1% 8/28/2016 -2.1% 8/29/2017 4.90%

8/30/2011 -2.8% 8/29/2012 -1.2% 8/30/2013 -8.6% 8/30/2014 6.0% 8/30/2015 -3.7% 8/29/2016 -2.8% 8/30/2017 10.50%

8/31/2011 2.9% 8/30/2012 1.5% 8/31/2013 -6.7% 8/31/2014 -5.5% 8/31/2015 5.4% 8/30/2016 3.9% 8/31/2017 12.50%

9/1/2011 0.4% 8/31/2012 4.7% 9/1/2013 -12.9% 9/1/2014 -3.4% 9/1/2015 -0.2% 8/31/2016 5.2% 9/1/2017 19.60%

9/2/2011 -8.3% 9/1/2012 0.0% 9/2/2013 -8.5% 9/2/2014 0.6% 9/2/2015 8.7% 9/1/2016 3.1% 9/2/2017 17.60%

9/3/2011 1.4% 9/2/2012 -3.1% 9/3/2013 -9.0% 9/3/2014 -6.5% 9/3/2015 1.5% 9/2/2016 0.6% 9/3/2017 25.70%

9/4/2011 0.3% 9/3/2012 -10.7% 9/4/2013 -4.2% 9/4/2014 -1.7% 9/4/2015 2.8% 9/3/2016 -1.3% 9/4/2017 9.70%

9/5/2011 -5.8% 9/4/2012 -0.6% 9/5/2013 -5.7% 9/5/2014 -2.7% 9/5/2015 6.6% 9/4/2016 2.3% 9/5/2017 9.00%

9/6/2011 -13.9% 9/5/2012 -5.7% 9/6/2013 -12.6% 9/6/2014 -2.6% 9/6/2015 -0.4% 9/5/2016 -5.8% 9/6/2017 3.20%

9/7/2011 -17.2% 9/6/2012 -4.3% 9/7/2013 2.0% 9/7/2014 -12.1% 9/7/2015 0.2% 9/6/2016 0.4% 9/7/2017 3.20%

9/8/2011 -21.8% 9/7/2012 -6.1% 9/8/2013 2.6% 9/8/2014 -11.9% 9/8/2015 -16.8% 9/7/2016 -5.8% 9/8/2017 1.10%

9/9/2011 -5.1% 9/8/2012 -1.8% 9/9/2013 5.2% 9/9/2014 -5.6% 9/9/2015 -16.0% 9/8/2016 -2.2% 9/9/2017 -1.80%

9/10/2011 1.9% 9/9/2012 -7.5% 9/10/2013 3.5% 9/10/2014 6.0% 9/10/2015 -16.6% 9/9/2016 -3.0% 9/10/2017 -1.40%

9/11/2011 0.5% 9/10/2012 -10.7% 9/11/2013 10.7% 9/11/2014 -2.1% 9/11/2015 -13.6% 9/10/2016 -4.1% 9/11/2017 9.80%

9/12/2011 2.0% 9/11/2012 -3.4% 9/12/2013 10.5% 9/12/2014 -8.1% 9/12/2015 -2.3% 9/11/2016 -0.1% 9/12/2017 0.90%

9/13/2011 -4.8% 9/12/2012 -0.1% 9/13/2013 6.1% 9/13/2014 -10.7% 9/13/2015 -11.6% 9/12/2016 -5.0% 9/13/2017 -2.50%

9/14/2011 0.6% 9/13/2012 -0.3% 9/14/2013 7.7% 9/14/2014 -11.3% 9/14/2015 -3.6% 9/13/2016 -11.7% 9/14/2017 -8.80%

9/15/2011 2.7% 9/14/2012 -4.5% 9/15/2013 9.0% 9/15/2014 -18.0% 9/15/2015 0.5% 9/14/2016 -14.5% 9/15/2017 -7.30%

9/16/2011 9.3% 9/15/2012 -9.1% 9/16/2013 -0.6% 9/16/2014 -14.0% 9/16/2015 5.2% 9/15/2016 -10.2% 9/16/2017 -10.10%

9/17/2011 7.8% 9/16/2012 0.5% 9/17/2013 9.0% 9/17/2014 -10.4% 9/17/2015 6.6% 9/16/2016 -9.5% 9/17/2017 -6.40%

9/18/2011 9.1% 9/17/2012 -1.8% 9/18/2013 11.3% 9/18/2014 -0.4% 9/18/2015 3.2% 9/17/2016 -10.0% 9/18/2017 -13.80%

9/19/2011 1.0% 9/18/2012 -0.1% 9/19/2013 9.0% 9/19/2014 7.8% 9/19/2015 2.9% 9/18/2016 -4.7% 9/19/2017 -8.20%

9/20/2011 3.0% 9/19/2012 3.3% 9/20/2013 8.9% 9/20/2014 3.4% 9/20/2015 -12.7% 9/19/2016 0.0% 9/20/2017 -11.20%

9/21/2011 4.3% 9/20/2012 -1.3% 9/21/2013 15.6% 9/21/2014 3.8% 9/21/2015 -4.0% 9/20/2016 -0.5% 9/21/2017 -12.90%

9/22/2011 2.0% 9/21/2012 -0.4% 9/22/2013 11.6% 9/22/2014 4.9% 9/22/2015 -2.3% 9/21/2016 -5.7% 9/22/2017 -17.20%

9/23/2011 3.4% 9/22/2012 3.9% 9/23/2013 8.2% 9/23/2014 4.3% 9/23/2015 -4.5% 9/22/2016 -1.5% 9/23/2017 -14.60%

9/24/2011 9.1% 9/23/2012 -2.3% 9/24/2013 10.3% 9/24/2014 6.2% 9/24/2015 -4.2% 9/23/2016 -8.8% 9/24/2017 -15.00%

9/25/2011 9.5% 9/24/2012 0.5% 9/25/2013 12.8% 9/25/2014 6.2% 9/25/2015 -5.6% 9/24/2016 -9.0% 9/25/2017 -8.30%

9/26/2011 10.6% 9/25/2012 4.3% 9/26/2013 18.9% 9/26/2014 6.9% 9/26/2015 0.8% 9/25/2016 1.0% 9/26/2017 -10.20%

9/27/2011 6.0% 9/26/2012 5.7% 9/27/2013 15.9% 9/27/2014 14.3% 9/27/2015 -2.4% 9/26/2016 16.5% 9/27/2017 -8.40%

9/28/2011 2.6% 9/27/2012 3.8% 9/28/2013 21.3% 9/28/2014 15.7% 9/28/2015 -4.9% 9/27/2016 4.9% 9/28/2017 -6.50%

9/29/2011 3.6% 9/28/2012 4.8% 9/29/2013 15.3% 9/29/2014 10.7% 9/29/2015 5.7% 9/28/2016 7.0% 9/29/2017 -9.80%

9/30/2011 6.6% 9/29/2012 3.3% 9/30/2013 15.7% 9/30/2014 10.3% 9/30/2015 0.8% 9/29/2016 5.6% 9/30/2017 -5.50%

10/1/2011 -6.9% 9/30/2012 -0.3% 10/1/2013 0.4% 10/1/2014 -16.2% 10/1/2015 4.1% 9/30/2016 3.2% 10/1/2017 -1.20%


10/2/2011 -14.0% 10/1/2012 -23.7% 10/2/2013 0.9% 10/2/2014 -22.1% 10/2/2015 -2.2% 10/1/2016 4.0% 10/2/2017 -10.30%

10/3/2011 -7.7% 10/2/2012 -22.9% 10/3/2013 2.3% 10/3/2014 -15.5% 10/3/2015 4.2% 10/2/2016 0.6% 10/3/2017 -5.30%

10/4/2011 5.7% 10/3/2012 -14.8% 10/4/2013 1.6% 10/4/2014 -16.5% 10/4/2015 1.6% 10/3/2016 -7.3% 10/4/2017 -1.50%

10/5/2011 0.4% 10/4/2012 -10.1% 10/5/2013 5.9% 10/5/2014 -8.1% 10/5/2015 8.4% 10/4/2016 -5.7% 10/5/2017 -0.20%

10/6/2011 3.4% 10/5/2012 -0.2% 10/6/2013 2.8% 10/6/2014 -12.3% 10/6/2015 5.8% 10/5/2016 -6.5% 10/6/2017 -1.20%

10/7/2011 10.1% 10/6/2012 -2.8% 10/7/2013 1.8% 10/7/2014 -14.0% 10/7/2015 2.3% 10/6/2016 -8.5% 10/7/2017 1.60%

10/8/2011 17.6% 10/7/2012 -1.9% 10/8/2013 8.7% 10/8/2014 -6.4% 10/8/2015 -2.1% 10/7/2016 -4.3% 10/8/2017 0.40%

10/9/2011 5.3% 10/8/2012 -3.4% 10/9/2013 -10.4% 10/9/2014 -8.7% 10/09/2015 -8.1% 10/8/2016 0.7% 10/9/2017 2.90%

10/10/2011 5.3% 10/9/2012 -4.7% 10/10/2013 3.9% 10/10/2014 0.7% 10/10/2015 -10.6% 10/9/2016 1.5% 10/10/2017 0.60%

10/11/2011 -0.6% 10/10/2012 3.1% 10/11/2013 13.1% 10/11/2014 -4.3% 10/11/2015 -12.0% 10/10/2016 0.2% 10/11/2017 -3.40%

10/12/2011 -10.9% 10/11/2012 13.8% 10/12/2013 17.9% 10/12/2014 -4.0% 10/12/2015 -15.6% 10/11/2016 -0.9% 10/12/2017 -2.50%

10/13/2011 -15.7% 10/12/2012 7.1% 10/13/2013 3.5% 10/13/2014 -8.1% 10/13/2015 -10.6% 10/12/2016 -9.0% 10/13/2017 -5.60%

10/14/2011 -13.1% 10/13/2012 14.5% 10/14/2013 16.0% 10/14/2014 -3.5% 10/14/2015 -16.7% 10/13/2016 -7.7% 10/14/2017 -8.70%

10/15/2011 -3.4% 10/14/2012 1.9% 10/15/2013 12.8% 10/15/2014 7.7% 10/15/2015 -13.4% 10/14/2016 -3.7% 10/15/2017 -3.20%

10/16/2011 -6.0% 10/15/2012 -1.5% 10/16/2013 10.9% 10/16/2014 5.0% 10/16/2015 3.0% 10/15/2016 -4.0% 10/16/2017 -3.10%

10/17/2011 -2.4% 10/16/2012 0.6% 10/17/2013 12.2% 10/17/2014 12.8% 10/17/2015 2.4% 10/16/2016 0.7% 10/17/2017 8.30%

10/18/2011 -1.6% 10/17/2012 -7.6% 10/18/2013 5.4% 10/18/2014 16.7% 10/18/2015 -2.2% 10/17/2016 -2.3% 10/18/2017 8.10%

10/19/2011 0.2% 10/18/2012 -2.8% 10/19/2013 8.8% 10/19/2014 12.5% 10/19/2015 9.4% 10/18/2016 -8.2% 10/19/2017 1.00%

10/20/2011 2.5% 10/19/2012 -2.0% 10/20/2013 8.4% 10/20/2014 10.0% 10/20/2015 8.0% 10/19/2016 -1.9% 10/20/2017 -5.90%

10/21/2011 1.5% 10/20/2012 4.8% 10/21/2013 8.8% 10/21/2014 14.0% 10/21/2015 7.1% 10/20/2016 -2.89% 10/21/2017 -12.90%

10/22/2011 5.8% 10/21/2012 3.1% 10/22/2013 6.7% 10/22/2014 12.4% 10/22/2015 7.7% 10/21/2016 1.24% 10/22/2017 -0.40%

10/23/2011 2.2% 10/22/2012 6.1% 10/23/2013 5.3% 10/23/2014 11.2% 10/23/2015 3.6% 10/22/2016 -2.39% 10/23/2017 7.60%

10/24/2011 5.7% 10/23/2012 6.1% 10/24/2013 7.4% 10/24/2014 13.0% 10/24/2015 8.6% 10/23/2016 -3.58% 10/24/2017 10.00%

10/25/2011 -10.3% 10/24/2012 19.6% 10/25/2013 10.2% 10/25/2014 9.7% 10/25/2015 2.8% 10/24/2016 -7.26% 10/25/2017 8.00%

10/26/2011 -4.7% 10/25/2012 17.5% 10/26/2013 5.4% 10/26/2014 8.1% 10/26/2015 8.6% 10/25/2016 -5.46% 10/26/2017 0.00%

10/27/2011 11.1% 10/26/2012 9.8% 10/27/2013 8.1% 10/27/2014 7.8% 10/27/2015 6.9% 10/26/2016 -3.19% 10/27/2017 7.20%

10/28/2011 19.0% 10/27/2012 11.6% 10/28/2013 -9.1% 10/28/2014 10.9% 10/28/2015 5.7% 10/27/2016 -7.18% 10/28/2017 -1.00%

10/29/2011 18.4% 10/28/2012 7.0% 10/29/2013 -6.4% 10/29/2014 12.1% 10/29/2015 3.8% 10/28/2016 0.14% 10/29/2017 -1.90%

10/30/2011 11.8% 10/29/2012 7.2% 10/30/2013 2.3% 10/30/2014 12.5% 10/30/2015 6.9% 10/29/2016 -3.36% 10/30/2017 -4.30%

10/31/2011 11.1% 10/30/2012 8.5% 10/31/2013 15.9% 10/31/2014 11.3% 10/31/2015 5.2% 10/30/2016 -4.66% 10/31/2017 -0.60%

11/1/2011 -8.6% 10/31/2012 11.1% 11/1/2013 -1.9% 11/1/2014 -20.0% 11/01/2015 -10.0% 10/31/2016 -2.23% 11/1/2017 6.70%

11/2/2011 -2.0% 11/1/2012 -3.2% 11/2/2013 -3.4% 11/2/2014 -10.0% 11/02/2015 -16.8% 11/1/2016 17.46% 11/2/2017 11.30%

11/3/2011 -9.8% 11/2/2012 0.0% 11/3/2013 -23.9% 11/3/2014 -1.6% 11/03/2015 -15.6% 11/2/2016 4.32% 11/3/2017 15.60%

11/4/2011 -37.9% 11/3/2012 1.9% 11/4/2013 -18.7% 11/4/2014 10.3% 11/04/2015 -2.5% 11/3/2016 12.61% 11/4/2017 7.60%

11/5/2011 -15.3% 11/4/2012 -3.4% 11/5/2013 -2.8% 11/5/2014 5.1% 11/05/2015 2.1% 11/4/2016 15.14% 11/5/2017 1.50%

11/6/2011 1.1% 11/5/2012 -13.0% 11/6/2013 6.9% 11/6/2014 -6.3% 11/06/2015 15.9% 11/5/2016 11.17% 11/6/2017 6.90%

11/7/2011 1.2% 11/6/2012 -10.7% 11/7/2013 4.3% 11/7/2014 -9.2% 11/07/2015 16.4% 11/6/2016 7.16% 11/7/2017 -0.90%

11/8/2011 7.4% 11/7/2012 -2.5% 11/8/2013 3.6% 11/8/2014 -1.1% 11/08/2015 16.3% 11/7/2016 10.02% 11/8/2017 1.30%

11/9/2011 11.7% 11/8/2012 -8.0% 11/9/2013 4.5% 11/9/2014 -0.1% 11/09/2015 0.0% 11/8/2016 11.15% 11/9/2017 0.10%

11/10/2011 20.8% 11/9/2012 -10.2% 11/10/2013 6.7% 11/10/2014 -15.3% 11/10/2015 -17.4% 11/9/2016 18.41% 11/10/2017 3.50%

11/11/2011 5.9% 11/10/2012 0.8% 11/11/2013 10.3% 11/11/2014 -19.4% 11/11/2015 15.1% 11/10/2016 26.53% 11/11/2017 -0.80%

11/12/2011 0.4% 11/11/2012 16.5% 11/12/2013 6.5% 11/12/2014 -15.3% 11/12/2015 22.9% 11/11/2016 18.16% 11/12/2017 -3.60%

11/13/2011 -1.8% 11/12/2012 27.5% 11/13/2013 -2.7% 11/13/2014 -3.4% 11/13/2015 22.6% 11/12/2016 14.60% 11/13/2017 -6.90%

11/14/2011 -2.9% 11/13/2012 29.6% 11/14/2013 -8.8% 11/14/2014 -12.8% 11/14/2015 18.7% 11/13/2016 17.53% 11/14/2017 -9.10%

11/15/2011 -4.8% 11/14/2012 22.6% 11/15/2013 -17.0% 11/15/2014 -2.4% 11/15/2015 2.0% 11/14/2016 13.75% 11/15/2017 -7.10%

11/16/2011 3.7% 11/15/2012 18.1% 11/16/2013 -14.4% 11/16/2014 -5.5% 11/16/2015 3.1% 11/15/2016 10.41% 11/16/2017 0.70%


11/17/2011 9.5% 11/16/2012 6.6% 11/17/2013 -7.4% 11/17/2014 9.8% 11/17/2015 22.1% 11/16/2016 4.45% 11/17/2017 2.60%

11/18/2011 2.2% 11/17/2012 -2.8% 11/18/2013 3.3% 11/18/2014 18.9% 11/18/2015 24.9% 11/17/2016 3.47% 11/18/2017 -14.50%

11/19/2011 -7.5% 11/18/2012 -13.3% 11/19/2013 -6.0% 11/19/2014 7.6% 11/19/2015 23.6% 11/18/2016 -4.87% 11/19/2017 -8.30%

11/20/2011 7.2% 11/19/2012 -1.7% 11/20/2013 2.8% 11/20/2014 5.2% 11/20/2015 13.0% 11/19/2016 -8.90% 11/20/2017 -11.00%

11/21/2011 5.0% 11/20/2012 12.6% 11/21/2013 -7.2% 11/21/2014 -4.7% 11/21/2015 9.5% 11/20/2016 -0.16% 11/21/2017 -5.40%

11/22/2011 18.8% 11/21/2012 10.5% 11/22/2013 18.1% 11/22/2014 13.8% 11/22/2015 8.0% 11/21/2016 8.06% 11/22/2017 -1.40%

11/23/2011 15.9% 11/22/2012 10.2% 11/23/2013 5.1% 11/23/2014 7.5% 11/23/2015 11.8% 11/22/2016 1.42% 11/23/2017 3.70%

11/24/2011 -8.6% 11/23/2012 11.0% 11/24/2013 10.8% 11/24/2014 17.9% 11/24/2015 5.2% 11/23/2016 -8.13% 11/24/2017 9.30%

11/25/2011 7.1% 11/24/2012 12.2% 11/25/2013 21.1% 11/25/2014 20.6% 11/25/2015 -19.3% 11/24/2016 -14.38% 11/25/2017 1.00%

11/26/2011 17.6% 11/25/2012 5.3% 11/26/2013 20.8% 11/26/2014 23.4% 11/26/2015 -15.7% 11/25/2016 -12.53% 11/26/2017 -4.30%

11/27/2011 11.5% 11/26/2012 -3.3% 11/27/2013 14.8% 11/27/2014 14.7% 11/27/2015 -21.8% 11/26/2016 -1.81% 11/27/2017 9.20%

11/28/2011 23.9% 11/27/2012 11.1% 11/28/2013 10.8% 11/28/2014 12.3% 11/28/2015 -2.6% 11/27/2016 -10.38% 11/28/2017 -8.30%

11/29/2011 21.7% 11/28/2012 -0.2% 11/29/2013 10.5% 11/29/2014 11.9% 11/29/2015 -7.9% 11/28/2016 -6.19% 11/29/2017 -17.50%

11/30/2011 17.0% 11/29/2012 4.4% 11/30/2013 10.2% 11/30/2014 7.7% 11/30/2015 12.9% 11/29/2016 -12.13% 11/30/2017 -13.40%

12/1/2011 -11.7% 11/30/2012 1.8% 12/1/2013 -5.8% 12/1/2014 -13.2% 12/1/2015 11.5% 11/30/2016 -9.81% 12/1/2017 8.00%

12/2/2011 -13.0% 12/1/2012 -14.3% 12/2/2013 6.8% 12/2/2014 -9.4% 12/2/2015 20.9% 12/1/2016 -2.20% 12/2/2017 3.00%

12/3/2011 -5.2% 12/2/2012 -19.6% 12/3/2013 -7.8% 12/3/2014 -20.5% 12/3/2015 17.1% 12/2/2016 -7.80% 12/3/2017 8.10%

12/4/2011 1.2% 12/3/2012 -30.4% 12/4/2013 -18.7% 12/4/2014 -32.7% 12/4/2015 9.4% 12/3/2016 -3.00% 12/4/2017 4.10%

12/5/2011 5.8% 12/4/2012 -7.4% 12/5/2013 -5.3% 12/5/2014 -17.0% 12/5/2015 18.6% 12/4/2016 -6.50% 12/5/2017 -11.30%

12/6/2011 5.3% 12/5/2012 -2.0% 12/6/2013 1.6% 12/6/2014 -17.3% 12/6/2015 17.6% 12/5/2016 4.10% 12/6/2017 -10.10%

12/7/2011 4.1% 12/6/2012 -14.0% 12/7/2013 2.2% 12/7/2014 -9.8% 12/7/2015 17.1% 12/6/2016 6.70% 12/7/2017 -10.00%

12/8/2011 6.0% 12/7/2012 -6.6% 12/8/2013 4.4% 12/8/2014 -16.2% 12/8/2015 8.4% 12/7/2016 1.20% 12/8/2017 -2.90%

12/9/2011 6.1% 12/8/2012 -14.1% 12/9/2013 12.3% 12/9/2014 -9.1% 12/9/2015 9.5% 12/8/2016 3.20% 12/9/2017 -12.00%

12/10/2011 1.2% 12/9/2012 -11.2% 12/10/2013 14.4% 12/10/2014 -8.6% 12/10/2015 2.7% 12/9/2016 0.50% 12/10/2017 -10.00%

12/11/2011 -5.7% 12/10/2012 -0.9% 12/11/2013 9.9% 12/11/2014 -13.6% 12/11/2015 -17.4% 12/10/2016 8.50% 12/11/2017 -8.20%

12/12/2011 4.7% 12/11/2012 1.8% 12/12/2013 7.9% 12/12/2014 -27.0% 12/12/2015 1.0% 12/11/2016 13.40% 12/12/2017 -10.70%

12/13/2011 3.4% 12/12/2012 -10.4% 12/13/2013 7.3% 12/13/2014 -19.8% 12/13/2015 5.6% 12/12/2016 16.70% 12/13/2017 -7.80%

12/14/2011 -2.4% 12/13/2012 -26.1% 12/14/2013 18.2% 12/14/2014 -5.3% 12/14/2015 -4.6% 12/13/2016 8.10% 12/14/2017 -5.00%

12/15/2011 6.5% 12/14/2012 -0.3% 12/15/2013 12.8% 12/15/2014 3.6% 12/15/2015 5.1% 12/14/2016 6.20% 12/15/2017 -4.20%

12/16/2011 6.7% 12/15/2012 -5.9% 12/16/2013 7.4% 12/16/2014 5.5% 12/16/2015 6.3% 12/15/2016 2.40% 12/16/2017 3.70%

12/17/2011 -2.0% 12/16/2012 -5.3% 12/17/2013 0.4% 12/17/2014 -19.8% 12/17/2015 8.9% 12/16/2016 16.90% 12/17/2017 -4.90%

12/18/2011 -8.1% 12/17/2012 -4.5% 12/18/2013 -9.2% 12/18/2014 -3.1% 12/18/2015 16.4% 12/17/2016 7.70% 12/18/2017 -3.90%

12/19/2011 -4.8% 12/18/2012 -19.1% 12/19/2013 -21.7% 12/19/2014 0.1% 12/19/2015 6.5% 12/18/2016 -4.40% 12/19/2017 -5.30%

12/20/2011 -2.6% 12/19/2012 1.8% 12/20/2013 3.6% 12/20/2014 8.5% 12/20/2015 -2.2% 12/19/2016 -1.20% 12/20/2017 7.90%

12/21/2011 -0.1% 12/20/2012 9.1% 12/21/2013 3.7% 12/21/2014 4.0% 12/21/2015 6.5% 12/20/2016 -15.00% 12/21/2017 -5.40%

12/22/2011 -1.5% 12/21/2012 12.9% 12/22/2013 7.7% 12/22/2014 -1.3% 12/22/2015 8.8% 12/21/2016 -14.90% 12/22/2017 -5.10%

12/23/2011 5.7% 12/22/2012 4.5% 12/23/2013 5.7% 12/23/2014 -13.7% 12/23/2015 -16.5% 12/22/2016 -2.40% 12/23/2017 -15.90%

12/24/2011 6.8% 12/23/2012 -4.9% 12/24/2013 7.3% 12/24/2014 -5.6% 12/24/2015 0.8% 12/23/2016 -8.20% 12/24/2017 -10.40%

12/25/2011 -1.9% 12/24/2012 -21.5% 12/25/2013 -14.4% 12/25/2014 -44.6% 12/25/2015 -17.4% 12/24/2016 3.60% 12/25/2017 1.10%

12/26/2011 4.3% 12/25/2012 -2.2% 12/26/2013 -2.9% 12/26/2014 -3.2% 12/26/2015 -1.5% 12/25/2016 11.20% 12/26/2017 -5.90%

12/27/2011 8.2% 12/26/2012 -11.0% 12/27/2013 5.1% 12/27/2014 2.1% 12/27/2015 3.1% 12/26/2016 -5.10% 12/27/2017 -11.20%

12/28/2011 9.1% 12/27/2012 -8.5% 12/28/2013 -2.9% 12/28/2014 8.5% 12/28/2015 7.7% 12/27/2016 -10.60% 12/28/2017 -10.60%

12/29/2011 5.7% 12/28/2012 4.8% 12/29/2013 3.2% 12/29/2014 2.0% 12/29/2015 -0.8% 12/28/2016 -14.60% 12/29/2017 -14.20%

12/30/2011 3.9% 12/29/2012 11.8% 12/30/2013 11.0% 12/30/2014 8.0% 12/30/2015 5.7% 12/29/2016 -7.50% 12/30/2017 -7.90%

12/31/2011 3.7% 12/30/2012 0.3% 12/31/2013 12.8% 12/31/2014 4.5% 12/31/2015 3.0% 12/30/2016 -0.90% 12/31/2017 -4.00%

12/31/2012 3.6% 12/31/2016 1.30%


Attachment V: SoCalGas Rule 23, excerpts


Rule No. 23 Sheet 1 CONTINUITY OF SERVICE AND INTERRUPTION OF DELIVERY


ADVICE LETTER NO. 5050 Dan Skopec DATE FILED Oct 25, 2016DECISION NO. 16-07-008 Vice President EFFECTIVE Nov 1, 20161C34 Regulatory Affairs RESOLUTION NO.

A. General The Utility will exercise reasonable diligence and care to furnish and deliver service to its customers,

and to avoid any interruption of same. The Utility shall not be liable for damages or otherwise for any failure to deliver gas or provide service to its customers, which failure in any way or manner results from breakage of its facilities, however caused, war, riots, acts of God, strikes, failure of or interruption in service, operating limitations or other conditions beyond its reasonable control.

B. Priority of Service In the event of a curtailment, as defined in Rule No. 1, the Utility shall curtail gas service to customers

as described in Section C, Curtailment of Service, herein. Customer usage will be assigned to appropriate end-use priority or service classifications as set forth below.

Core Service Priority 1 All residential usage regardless of size. All nonresidential usage less than 20,800

therms per active month*, excluding usage reclassified to noncore service pursuant to customer request. All electric generation, refinery and enhanced oil recovery (EOR) usage less than 20,800 therms per active month* electing core service.

Priority 2A All nonresidential usage of 20,800 therms or greater per active month* eligible for

core service, not electing noncore service. Noncore Service Noncore Service includes: (1) commercial and industrial usage electing noncore service, (2) electric

generation, EOR, and refinery usage less than 20,800 therms per active month* electing noncore service, and (3) all usage ineligible for core service, including (a) refinery and EOR usage of 20,800 therms or greater per active month* and (b) all electric generation usage from generators greater than 1 megawatt (MW) system rated generating capacity, based on net continuous power output with usage of 20,800 therms or greater per active month*.

____________________________ * A customer shall be considered to meet the size criteria of 20,800 therms or greater per active month when on an

annualized basis, for any period of 12 contiguous months within the most recent 24-month period, the customer’s active month consumption averages 20,800 therms or greater. An active month is one in which consumption exceeds 1,000 therms.

D

Page 1



(Continued)



C. Curtailment of Service 1. Effectuation of Curtailment When in the judgment of the Utility, operating conditions require curtailment of service within one

or more Local Service Zones, as defined in Rule No. 1, or within a sub-zonal area, such curtailment shall be effectuated in the order and manner described below, unless otherwise specified in this rule. To the extent operationally feasible, if a capacity constraint can be addressed by curtailing multiple zones while minimizing individual customer impacts, the Utility will curtail multiple zones or subsets thereof.

(1) In the event of a curtailment being called based on day-ahead forecasts of peak electric

generation load as described in C.1.(2), all Dispatchable Electric Generation not currently forecasted to be operating at the time the curtailment order is effective. In the event of a curtailment being called based on real-time demand, all Dispatchable Electric Generation not operating when a curtailment is issued.

(2) Up to 60% of Dispatched Electric Generation load during November through March and up

to 40% of Dispatched Electric Generation load during April through October. To the extent operationally feasible, the Utility will attempt to base these curtailments on day-ahead forecasts of peak electric generation loads provided by the relevant Electric Grid Operator(s) as defined in Rule No. 1. To the extent operationally feasible, the Utility will work with affected Electric Grid Operator(s) on a best efforts basis to reallocate the aggregate maximum allowed usage for the remaining Dispatched Electric Generation load within the affected Local Service Zone(s) among all of the Dispatchable Electric Generation facilities within the affected Local Service Zone(s) to maintain grid reliability and prevent firm electric load shedding. Any such reallocation shall be at the sole discretion of the Utility, and the default in the absence of reallocation shall be pro rata within each affected Local Service Zone(s). If the relevant Electric Grid Operator(s) informs the Utility that a proposed curtailment of Dispatched Electric Generation load pursuant to this section could adversely affect electric grid reliability or cause shedding firm electric customer load, the Utility may in its sole discretion reduce the proposed curtailment of Dispatched Electric Generation load pursuant to this section and move to the next curtailment step.

D N N,D N | | N D N | | | N D N | | | | | | | | | | | | | | N

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(Continued)



C. Curtailment of Service (Continued) 1. Effectuation of Curtailment (Continued)

(3) Up to 100% of non-electric generation noncore and noncore cogeneration usage on a pro rata basis, except for pre-established refinery minimum usage requirements. Electric generation load that is not dipatchable by an Electric Grid Operator and therefore not subject to curtailment in step 2 will be considered non-electric generation noncore load for the purposes of curtailment. Refineries, including cogeneration and ancillary facilities serving refineries, will be permitted to establish, subject to the Utility’s reasonable agreement, pre-established minimum usage requirements that are not subject to curtailment in this step. Refinery minimum usage requirements shall be established at the usage level required to safely operate refinery processing units, to avoid material damage to operating equipment and to avoid operational outages extending materially beyond the curtailment period and shall take into account other relevant factors such as the length of notice provided by the Utility.

(4) a) Up to 100% of remaining refinery load not curtailed in step 3.

b) Up to 100% of remaining Dispatched Electric Generation load not curtailed in step 2. To the extent operationally feasible, the Utility will work with the affected Electric Grid Operator(s) on a best efforts basis to reallocate the aggregate maximum allowed usage for any remaining Dispatched Electric Generation load within the affected Local Service Zone(s) among all of the Dispatched Electric Generation facilities within the affected Local Service Zone(s) to maintain grid reliability and prevent firm electric load shedding. Any such reallocation shall be at the sole discretion of the Utility, and the default in the absence of reallocation shall be pro rata within each affected Local Service Zone(s).

(5) All Priority 2A service on a pro rata basis. (6) All Priority 1 non-residential service on a pro rata basis. (7) All Priority 1 residential service on a pro rata basis.

D N | | | | | | | | | N D N | | | | | | | N D T T T D

Page 3

Attachment W: SDG&E Rule 14, excerpts



RULE 14 Sheet 1

SHORTAGE OF GAS SUPPLY, INTERRUPTION OF DELIVERY, AND PRIORITY OF SERVICE

(Continued) 1C6 Issued by Date Filed Oct 25, 2016 Advice Ltr. No. 2522-G Dan Skopec Effective Nov 1, 2016 Vice President Decision No. D.16-07-008 Regulatory Affairs Resolution No.

A. Service Conditions

The utility will use reasonable diligence and care to avoid any shortage or interruption of gas supply. The utility shall not be liable in damages or otherwise for any failure to deliver gas to the customer, which failure in any way or manner results from breakage of its facilities, however caused, war, riots, acts of God, strikes, failure of, or interruption in, gas supply, mandatory or voluntary curtailments ordered by the Public Utilities Commission, or other conditions beyond its reasonable control.

B. Temporary Suspension of Service

Whenever necessary for making repairs or improvements to its system, the utility may temporarily suspend the delivery of gas. In all such cases, the utility will provide as much notice as circumstances reasonably permit. Repairs or improvements will be carried out as rapidly as may be practicable, and, if practicable, at such times as will cause the least inconvenience to the customers.

C. Restoration of Service

When curtailment of service is to be decreased, restoration of service shall be made (a) in the same manner as described in Section H but inversely to the order given, and (b) to the level of service which in the judgment of the Utility can be provided. However, the Utility reserves the right to restore service in such order as it deems necessary irrespective of the curtailment order described in Section H herein.

D. Operating Emergency In the event a customer declares an operating emergency, service may be made available out of the

normal curtailment pattern, if in the judgment of the utility it is possible to do so. To the extent operationally feasible, Utility will give preference to critical customers as defined in Rule 1 when they declare an operating emergency.

D T N N T N N N N

Page 1



RULE 14 Sheet 2



E. Gas Transportation Service Levels

The utility shall offer the following levels of gas transportation service, and the service levels listed below shall serve as a basis for gas curtailment:

1. Core Service

Firm Inter- & Intrastate Transportation Service. Gas Purchased from the utility. Optional Intrastate Transportation-Only Service. Curtailment based on end-use priorities. Includes all P-1 and P-2A end-use priorities.

2. Noncore Service1

Local Transportation Service. Minimum One-Month Contract Term. No Use-or-Pay Obligations or Charges.

Gas curtailment within each service level is described in Section H. hereunder. In order to notify noncore customers of gas curtailments, the customer must provide and maintain

accurate primary and alternate day/night contact phone numbers and contact names who will be responsible for responding to the utility's notice to curtail gas services. The inability of the utility to notify a noncore gas customer of curtailment due to having out-dated and/or incorrect phone numbers and contact names, will result in the customer being changed to core status for the next 12-month period.

F. End-Use Priority Classification In the event of a curtailment within the core service, the utility will curtail gas supplies in the reverse

order of the assigned end-use priorities described below:

Priority Description

P-1 All residential use regardless of size. All non-residential use through a single meter that is equal to or less than 20,800 therms.

P-2A Non-residential use through a single meter that is greater than an annual monthly

average of 20,800 therms, where the customer has made a minimum two-year election to receive core reliability service.

Electric generation start-up and igniter fuel.

________________________________________ 1. Customers electing noncore service must have Automatic Meter Reading (AMR) equipment installed at customer’s expense at a condition of noncore service.

T D, T D, T T T T

Page 2



RULE 14 Sheet 3



G. Delivery Point Curtailment Delivery of natural gas may be interrupted in the event of projected or actual capacity constraints or projected or actual supply shortages at system delivery points. In the event of a localized curtailment, customers in the unconstrained areas may continue to receive service while customers that are equal or higher in the curtailment order are curtailed in the constrained area. H. Curtailment of Service

1. When in the judgment of the Utility, operating conditions require curtailment of service, such curtailment shall be effectuated in the order and manner described below, unless otherwise specified in this rule.

(1) In the event of a curtailment being called based on day-ahead forecasts of peak electric generation load as described in H.1.(2), all Dispatchable Electric Generation not currently forecasted to be operating at the time the curtailment order is effective. In the event of a curtailment being called based on real-time demand, all Dispatchable Electric Generation not operating when a curtailment order is issued.

(2) Up to 60% of Dispatched Electric Generation load during November through March and up to 40% of Dispatched Electric Generation load during April through October. To the extent operationally feasible, Utility will attempt to base these curtailments on day-ahead forecasts of peak electric generation loads provided by the relevant electric grid operator(s). To the extent operationally feasible, Utility will work with affected grid operators on a best efforts basis to reallocate the aggregate maximum allowed usage for the remaining Dispatched Electric Generation load among all of the Dispatchable Electric Generation facilities to maintain grid reliability and prevent firm electric load shedding. Any such reallocation shall be at the sole discretion of the Utility, and the default in the absence of reallocation shall be pro rata. If the relevant electric grid operator(s) informs Utility that a proposed curtailment of Dispatched Electric Generation load pursuant to this section could adversely affect electric grid reliability or cause shedding firm electric customer load, Utility may in its sole discretion reduce the proposed curtailment of Dispatched Electric Generation load pursuant to this section and move to the next curtailment step.

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RULE 14 Sheet 4



H. Curtailment of Service (continued) 1. When in the judgment of the Utility, operating conditions require curtailment of service, such

curtailment shall be effectuated in the order and manner described below, unless otherwise specified in this rule. (continued)

(3) Up to 100% of non-electric generation noncore and noncore cogeneration usage on a pro rata

basis. Electric generation load that is not dispatchable by an electric grid operator and therefore not subject to curtailment in step 2 will be considered non-electric generation noncore load for the purposes of curtailment.

(4) Up to 100% of remaining Dispatched Electric Generation load not curtailed in step 2. To the extent operationally feasible, Utility will work with the affected grid operators on a best efforts basis to reallocate the aggregate maximum allowed usage for any remaining Dispatched Electric Generation load among all of the Dispatched Electric Generation facilities to maintain grid reliability and prevent firm electric load shedding. Any such reallocation shall be at the sole discretion of the Utility, and the default in the absence of reallocation shall be pro rata.

(5) All Priority 2A service on a pro rata basis. (6) All Priority 1 non-residential service on a pro rata basis. (7) All Priority 1 residential service on a pro rata basis.

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Attachment X: SoCalGas Rule 30, excerpts


Rule No. 30 Sheet 1 TRANSPORTATION OF CUSTOMER-OWNED GAS


ADVICE LETTER NO. 4240 Lee Schavrien DATE FILED May 6, 2011DECISION NO. 11-04-032 Senior Vice President EFFECTIVE Jun 5, 20111C16 Regulatory Affairs RESOLUTION NO.

The general terms and conditions applicable whenever the Utility System Operator transports customer-owned gas, including wholesale customers, the Utility Gas Procurement Department, other end-use customers, aggregators, marketers and storage customers (referred to herein as “customers") over its system are described herein. A. General

1. Subject to the terms, limitations and conditions of this rule and any applicable CPUC authorized tariff schedule, directive, or rule, the customer will deliver or cause to be delivered to the Utility and accept on redelivery quantities of gas which shall not exceed the Utility's capability to receive or redeliver such quantities. The Utility will accept such quantities of gas from the customer or its designee and redeliver to the customer on a reasonably concurrent basis an equivalent quantity, on a therm basis, to the quantity accepted.

2. The customer warrants to the Utility that the customer has the right to deliver the gas provided for in

the customer's applicable service agreement or contract (hereinafter "service agreement") and that the gas is free from all liens and adverse claims of every kind. The customer will indemnify, defend and hold the Utility harmless against any costs and expenses on account of royalties, payments or other charges applicable before or upon delivery to the Utility of the gas under such service agreement.

3. The point(s) where the Utility will receive the gas into its intrastate system (point(s) of receipt, as

defined in Rule No. 1) and the point(s) where the Utility will deliver the gas from its intrastate system to the customer (point(s) of delivery, as defined in Rule No. 1) will be set forth in the customer's applicable service agreement. Other points of receipt and delivery may be added by written amendment thereof by mutual agreement. The appropriate delivery pressure at the point(s) of delivery to the customer shall be that existing at such point(s) within the Utility's system or as specified in the service agreement.

B. Quantities 1. The Utility shall as nearly as practicable each day redeliver to customer and customer shall accept, a

like quantity of gas as is delivered by the customer to the Utility on such day. It is the intention of both the Utility and the customer that the daily deliveries of gas by the customer for transportation hereunder shall approximately equal the quantity of gas which the customer shall receive at the point(s) of delivery. However, it is recognized that due to operating conditions either (1) in the fields of production, (2) in the delivery facilities of third parties, or (3) in the Utility's system, deliveries into and redeliveries from the Utility's system may not balance on a day-to-day basis. The Utility and the customer will use all due diligence to assure proper load balancing in a timely manner.

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(Continued)


ADVICE LETTER NO. 4842 Dan Skopec DATE FILED Jul 31, 2015DECISION NO. Vice President EFFECTIVE Apr 1, 20162C12 Regulatory Affairs RESOLUTION NO.

B. Quantities (Continued) 2. The gas to be transported hereunder shall be delivered and redelivered as nearly as practicable at

uniform hourly and daily rates of flow. The Utility may refuse to accept fluctuations in excess of ten percent (10%) of the previous day's deliveries, from day to day, if in the Utility's opinion receipt of such gas would jeopardize other operations. Customers may make arrangements acceptable to the Utility to waive this requirement.

3. The Utility does not undertake to redeliver to the customer any of the identical gas accepted by the

Utility for transportation, and all redelivery of gas to the customer will be accomplished by substitution on a therm-for-therm basis.

4. Transportation customers, including the Utility Gas Procurement Department, wholesale customers,

contracted marketers, and Core Transport Agents (CTAs) will be provided monthly balancing services in accordance with the provisions of Schedule No. G-IMB.

C. Electronic Bulletin Board 1. The Utility prefers and encourages customers, including the Utility Gas Procurement Department, to

use Electronic Bulletin Board (EBB) as defined in Rule No. 1 to submit their transportation nominations to the Utility. Imbalance trades are to be submitted through EBB or by means of the Imbalance Trading Agreement Form (Form 6544). Use of EBB is not mandatory for transportation only customers.

2. Transportation nominations may be submitted manually or through EBB. D. Operational Requirements 1. Customer Representation The customer must provide to the Utility the name(s) of any agents ("Agent") used by the customer

for delivery of gas to the Utility for transportation service hereunder and their authority to represent customer.

A customer may choose only one of the following gas supply arrangements: 1) one Contracted

Marketer, 2) one or multiple Agents (in addition to a Contracted Marketer if desired), or 3) itself for purposes of nominating to its end-use account (OCC).

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SOUTHERN CALIFORNIA GAS COMPANY Revised CAL. P.U.C. SHEET NO. 51793-G LOS ANGELES, CALIFORNIA CANCELING Revised CAL. P.U.C. SHEET NO. 47354-G*


(Continued)



D. Operational Requirements (Continued)

2. Receipt Points

Utility accepts nominations from transportation customers or their representatives at the following Receipt Points into the SoCalGas system, as referenced in Schedule No. G-BTS*:

• El Paso Pipeline at Blythe (Southern Transmission Zone) • North Baja Pipeline at Blythe (Southern Transmission Zone) • Transportadora de Gas Natural de Baja California at Otay Mesa (Southern Transmission

Zone) • Kern River Pipeline and Mojave Pipeline (Wheeler Transmission Zone) • PG&E at Kern River Station (Wheeler Transmission Zone) • Occidental of Elk Hills at Gosford (Wheeler Transmission Zone) • Transwestern Pipeline at North Needles (Northern Transmission Zone) • Transwestern Pipeline at Topock (Northern Transmission Zone) • El Paso Pipeline at Topock (Northern Transmission Zone) • Questar Southern Trails Pipeline at North Needles (Northern Transmission Zone) • Kern River Pipeline and Mojave Pipeline at Kramer Junction (Northern Transmission Zone) • Line 85 (California Supply) • North Coastal (California Supply) • Other (California Supply) • Storage

* Additional Receipt Points will be added as they are established in the future.

3. Backbone Transmission Capacity

Each day, Receipt Point and Backbone Transmission Zone capacities will be set at their physical operating maximums under the operating conditions for that day. The Utility will schedule nominations for each Receipt Point and Backbone Transmission Zone to the maximum operating capacity of that individual Receipt Point or Backbone Transmission Zone. The maximum operating capacity is defined as the facility design or contractual limitation to deliver gas into the Utility’s system adjusted for operational constraints (i.e. maintenance, localized restrictions, and upstream delivery pressures) as determined each day.

The NAESB elapsed pro rata rules require that the portion of the scheduled quantity that would have theoretically flowed up to the effective time of the intraday nomination be confirmed, based upon a cumulative uniform hourly quantity for each nomination period affected. As such, the scheduled quantities for each shipper are subject to change in the Intraday 1 Cycle, the Intraday 2 Cycle, and the Intraday Cycle 3. However, each shipper’s resulting scheduled quantity for the Gas Day will be no less than the elapsed prorated scheduled quantity for that shipper.

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SOUTHERN CALIFORNIA GAS COMPANY Revised CAL. P.U.C. SHEET NO. 51794-G LOS ANGELES, CALIFORNIA CANCELING Revised CAL. P.U.C. SHEET NO. 49388-G*


(Continued)




3. Backbone Transmission Capacity (Continued) Each day, the Utility will use the following rules to confirm nominations to the Receipt Point and Backbone Transmission Zone maximum operating capacities. The Utility will also use the following rules to confirm nominations to the system capacity limitation as defined in Section F for OFO events during the Intraday 1 and Intraday 2 cycles; and during the Intraday 2 cycle when an OFO event is not called and nominations exceed system capacity. Confirmation Order:

• Nominations using Firm Primary backbone transportation rights will be first; pro-rated if over-nominated*.

• Nominations using Firm Alternate backbone transportation rights within the associated transmission zone will be second (“Firm Alternate Within-the-Zone”); pro-rated if over-nominated.

• Nominations using Firm Alternate backbone transportation rights outside the associated transmission zone will be third (“Firm Alternate Outside-the-Zone”); pro-rated if over-nominated.

• Nominations using Interruptible backbone transportation rights will be fourth, pro-rated if over-nominated.

• Southern Transmission Receipt Points will not be reduced in any cycle below 110% of the Southern System minimum flowing supply requirement established by the Gas Control Department.

Bumping Rules:

• Firm Primary rights can “bump” any Firm Alternate scheduled quantities through the Evening Cycle.

• Firm Alternate Within-the-Zone rights can “bump” Firm Alternate Outside-the-Zone scheduled quantities through the Evening Cycle.

• Firm Primary and any Firm Alternate can “bump” interruptible scheduled quantities through the Intraday 2 Cycle subject to the NAESB elapsed pro-rata rules.

• Bumping will not be allowed in the Intraday 3 Cycle. * If the available firm capacity at a particular receipt point or within a particular transmission zone

is less than the firm capacity figures stated in Schedule No. G-BTS, scheduling of firm backbone transportation capacity nominations will be pro rata within each scheduling cycle. Any nominations of firm backbone transportation rights acquired through the addition of Displacement Backbone Transmission Capacity facilities will be reduced pro rata to zero at the applicable receipt point or within the applicable transmission zone prior to other firm backbone transportation rights nominations being reduced.

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(Continued)


ADVICE LETTER NO. 4996 Dan Skopec DATE FILED Jul 25, 2016DECISION NO. 16-06-039 Vice President EFFECTIVE Sep 1, 20165C13 Regulatory Affairs RESOLUTION NO.


3. Backbone Transmission Capacity (Continued)

Priority Rules: a. Firm primary scheduled quantities in the Evening Cycle will have priority over a new firm

primary nomination made in the Intraday 1 Cycle. b. Firm Alternate Inside-the-Zone scheduled quantities in the Evening Cycle will have priority

over a new Firm Alternate Inside-the-Zone nomination made in the Intraday 1 Cycle. c. Firm Alternate Outside-the-Zone scheduled quantities in the Evening Cycle will have

priority over a new Firm Alternate Outside-the-Zone nomination made in the Intraday 1 Cycle.

d. Interruptible scheduled quantities in the Evening Cycle will have priority over a new Interruptible nomination made in the Intraday 1 Cycle.

e. This same structure will be applied in going from Intraday 1 Cycle (Cycle 3) to Intraday 2 Cycle (Cycle 4) to Intraday 3 Cycle (Cycle 5). However, this hierarchy will not affect Intraday 4 Cycle (Cycle 6) nominations or the elapsed pro-rata rule.

4. Storage Service Capacity

Each day, storage injection and withdrawal capacities will be set at their physical operating maximums under the operating conditions for that day and posted on the Utility’s EBB. These capacities will take into account offsetting injection or withdrawal activity that effectively increase withdrawal or injection capacities. Injection nominations will be held to the injection capacity specified in the Operational Flow Order (OFO) calculation on the EBB in every flowing cycle regardless of OFO status.* The Utility will use the following rules to limit the nominations to the storage maximums. As necessary, withdrawal or injection allocated to the daily balancing function will be set aside and given first priority every day.

• Nominations using Firm storage rights will have the next priority, pro-rated, if necessary to the available storage capacity.

• All other nominations using Interruptible storage rights will have the lowest priority, pro-rated if over-nominated based on the daily volumetric price paid.

• On low OFO days the volume of interruptible withdrawal will be cut in half relative to the calculation on a non-OFO day. If interruptible nominations immediately prior to the low OFO were above this level, then they will be held constant through the low OFO.

• Firm storage rights can “bump” interruptible scheduled storage quantities through the Intraday 3 cycle.

Notice to bumped parties will be provided via the Transactions module in EBB. Bumping is subject

to the NAESB elapsed prorata rules.

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(Continued)




5. Off-System Delivery (OSD) Service

For each flow date, the Utility will determine the quantity of capacity available for off-system deliveries. The quantity will include that available via physical redelivery from the Utility system along with displacement of forward haul flowing supplies. For each nomination cycle, the Utility customers who have contracted with the Utility for off-system delivery service may submit a nomination for such service pursuant to Schedule No. G-OSD and Section D.6. “Nominations” below, for deliveries to the PG&E system and to the Utility Transmission system’s interconnection points with all interstate and international pipelines, but excluding California-produced gas supply lines. The following rules will be used in scheduling of Off-System Delivery Services:

• Nominations using Firm OSD rights will have first priority; pro-rated if over-nominated. • Nominations using Interruptible OSD rights will have second priority; pro-rated if over-

nominated. • Firm OSD rights can “bump” Interruptible OSD scheduled quantities through the Intraday 2

Cycle, subject to the NAESB elapsed pro-rata rules. • Bumping of Interruptible OSD rights by Firm OSD rights will not be allowed in the

Intraday 3 Cycle. • Both Firm and Interruptible OSD rights, at any Delivery Point, can be reduced in any cycle,

including during curtailment events, (subject to the NAESB elapsed pro rata rules) if, in the sole judgment of the Utility, the discontinuation or reduction of OSD service at that Delivery Point would diminish the need for the Utility to bring additional gas into the Utility’s system at an additional cost or reduce the level of curtailment to any Utility customer.

• Reduction of Interruptible OSD nominations at any Delivery Point will be prorated at that particular Delivery Point.

• Reduction of Firm OSD nominations at any Delivery Point will be prorated at that particular Delivery Point.

D N D,N D,N N N

D

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(Continued)




6. Nominations

The customer shall be responsible for submitting gas service nominations to the Utility no later than the deadlines specified below.

Each nomination shall include all information required by the Utility’s nomination procedures. Nominations received by the Utility will be subject to the conditions specified in the service agreements with the Utility. The Utility may reject any nomination not conforming to the requirements in these rules or in applicable service agreements. The customer shall be responsible for making all corresponding upstream nomination/confirmation arrangements with the interconnecting pipeline(s) and/or operator(s). Evening and Intraday nominations may be used to request an increase or decrease to scheduled volumes or a change to receipt or delivery points. Intraday nominations do not roll from day to day. Nominations submitted in any cycle will automatically roll to subsequent cycles for the specified flow date and from day-to-day through the end date or until the end date is modified by the nominating entity. Nominations may be made in the following manner: FROM TO

Pipeline/CA Producer Backbone Transportation Service Contract Backbone Transportation Service Contract End User, Contracted Marketer, CTA Backbone Transportation Service Contract Citygate Pool Account Backbone Transportation Service Contract Storage Account Citygate Pool Account End User, Contracted Marketer, CTA Citygate Pool Account Citygate Pool Account Storage Account End User, Contracted Marketer, CTA Citygate Pool Account Storage Account Storage Account Citygate Pool Account Storage Account Storage Account Storage Account Off-System Delivery Contract Citygate Pool Account Off-System Delivery Contract End User, Contracted Marketer, CTA Storage Account

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(Continued)




6. Nominations (Continued)

FROM TO (Continued)

Off-System Delivery Contract PG&E Pipeline (at Kern River Station) Off-System Delivery Contract Mojave Pipeline (at Wheeler Ridge) Off-System Delivery Contract Mojave Pipeline (at Kramer Junction) Off-System Delivery Contract Kern River Pipeline (at Wheeler Ridge) Off-System Delivery Contract Kern River Pipeline (at Kramer Junction) Off-System Delivery Contract Questar Southern Trails Pipeline (at North Needles) Off-System Delivery Contract Transwestern Pipeline (at North Needles) Off-System Delivery Contract Transwestern Pipeline (at Topock) Off-System Delivery Contract El Paso Pipeline (at Topock) Off-System Delivery Contract El Paso Pipeline (at Blythe) Off-System Delivery Contract North Baja Pipeline (at Blythe) Off-System Delivery Contract Transportadora de Gas Natural de Baja California (at Otay Mesa) Receipt Point Pool Account Receipt Point Pool Account Receipt Point Pool Account Backbone Transportation Contract

7. Timing

All times referred to below are in Pacific Clock Time. Requests for deadline extensions may be granted for 15 minutes only if request is made prior to the deadlines shown below. Timely Cycle

Transportation nominations submitted via EBB for the Timely Nomination cycle must be received by the Utility by 11:00 a.m. one day prior to the flow date. Nominations submitted via fax must be received by the Utility by 10:00 a.m. one day prior to the flow date. Timely nominations will be effective at 7:00 a.m. on the flow date.

Evening Cycle Nominations submitted via EBB for the Evening Nomination cycle must be received by the Utility by 4:00 p.m. one day prior to the flow date. Nominations submitted via fax must be received by the Utility by 3:00 p.m. one day prior to the flow date. Evening nominations will be effective at 7:00 a.m. on the flow date.

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(Continued)


ADVICE LETTER NO. 5064 Dan Skopec DATE FILED Dec 1, 2016DECISION NO. Vice President EFFECTIVE Dec 1, 20169C8 Regulatory Affairs RESOLUTION NO.


7. Timing (Continued)

Intraday 1 Cycle

Nominations submitted via EBB for the Intraday 1 Nomination cycle must be received by the Utility by 8:00 a.m. on the flow date. Nominations submitted via fax must be received by the Utility by 7:00 a.m. on the flow date. Intraday 1 nominations will be effective at 12:00 p.m. the same day. Intraday 2 Cycle Nominations submitted via EBB for the Intraday 2 Nomination cycle must be received by the Utility by 12:30 p.m. on the flow date. Nominations submitted via fax must be received by the Utility by 11:30 a.m. on the flow date. Intraday 2 nominations will be effective at 4:00 p.m. the same day.

Intraday 3 Cycle Nominations submitted via EBB for Intraday 3 Nomination cycle must be received by the Utility by 5:00 p.m. on the flow date. Nominations submitted via fax must be received by the Utility by 4:00 p.m. on the flow date. Intraday 3 nominations will be effective at 8:00 p.m. the same day. Intraday 4 Cycle

Nominations submitted via EBB for the Intraday 4 Nomination cycle must be received by the Utility by 9:00 p.m. Pacific Clock Time on the flow date. Nominations submitted via fax must be received by the Utility by 8:00 p.m. Pacific Clock Time on the flow date. Temporary provisions regarding the trading of scheduled quantities and daily imbalances are provided in Section N.*

Intraday 4 nominations are available only for firm nominations relating to the injection of existing flowing supplies into a storage account or for firm nominations relating to the withdrawal of gas in storage to meet an identified customer’s usage. A customer may make Intraday 4 nominations from a third-party storage provider that is directly connected to the Utility’s system or from the Utility’s storage, subject to the storage provider or the Utility being able to deliver or accept the daily quantity nominated for Intraday 4 within the remaining hours of the flow day and the Utility’s having the ability to deliver or accept the required hourly equivalent flow rate during the remaining hours of the flow day. Third-party storage providers will be treated on a comparable basis with the Utility’s storage facilities to the extent that it can provide the equivalent service and operations.

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SOUTHERN CALIFORNIA GAS COMPANY Revised CAL. P.U.C. SHEET NO. 47360-G* LOS ANGELES, CALIFORNIA CANCELING Revised CAL. P.U.C. SHEET NO. 46261-G 46262-G

Rule No. 30 Sheet 10 T TRANSPORTATION OF CUSTOMER-OWNED GAS

(Continued)


ADVICE LETTER NO. 4258 Lee Schavrien DATE FILED Jul 15, 2011DECISION NO. 11-03-029 Senior Vice President EFFECTIVE Oct 1, 201210C24 RESOLUTION NO.


8. Confirmation and Ranking Process

A ranking must be received by the Utility at the time the nomination or the confirmation is submitted. The nominating party will rank its supplies and the confirming party will rank its markets. The Utility will then balance the pipeline system using the “lesser of” rule and the rankings submitted.

The ranking will automatically roll from cycle-to-cycle and day-to-day until the nomination end date, unless modified by the nominating entity. If no ranking is submitted at the time the nomination is submitted, the Utility will assign the lowest ranking to the nomination. The Utility will compare the nominations received for each transaction and the corresponding confirmation. If the two quantities do not agree, the “lesser of” the two quantities will be the quantity scheduled by the Utility. Subject to the Utility receiving notification of confirmed transportation from the applicable upstream pipeline(s) and/or operator(s), the Utility will provide scheduled quantities on EBB.

9. As between the customer and the Utility, the customer shall be deemed to be in control and possession of the gas to be delivered hereunder and responsible for any damage or injury caused thereby until the gas has been delivered at the point(s) of receipt. The Utility shall thereafter be deemed to be in control and possession of the gas after delivery to the Utility at the point(s) of receipt and shall be responsible for any damage or injury caused thereby until the same shall have been redelivered at the point(s) of delivery, unless the damage or injury has been caused by the quality of gas originally delivered to the Utility, for which the customer shall remain responsible.

10. Any penalties or charges incurred by the Utility under an interstate or intrastate supplier contract as a

result of accommodating transportation service shall be paid by the responsible customer.

11. Customers receiving service from the Utility for the transportation of customer-owned gas shall pay any costs incurred by the Utility because of any failure by third parties to perform their obligations related to providing such service.

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(Continued)


ADVICE LETTER NO. 5297 Dan Skopec SUBMITTED May 22, 2018DECISION NO. 16-06-039, 16-12-015 Vice President EFFECTIVE Jun 1, 201811C8 Regulatory Affairs RESOLUTION NO.

E. Interruption of Service 1. The customer's transportation service priority shall be established in accordance with the definitions

of Core and Noncore service, as set forth in Rule No. 1, and the provisions of Rule No. 23, Continuity of Service and Interruption of Delivery. If the customer's gas use is classified in more than one service priority, it is the customer's responsibility to inform the Utility of such priorities applicable to the customer's service. Once established, such priorities cannot be changed during a curtailment period.

2. The Utility shall have the right, without liability, to interrupt the acceptance or redelivery of gas

whenever it becomes necessary to test, alter, modify, enlarge or repair any facility or property comprising the Utility's system or otherwise related to its operation. When doing so, the Utility will try to cause a minimum of inconvenience to the customer. Except in cases of unforeseen emergency, the Utility shall give a minimum of ten (10) days advance written notice of such activity.

F. Nominations in Excess of System Capacity

1. In the event customers fail to adequately reduce their transportation nominations, the Utility shall reduce the confirmed receipt point access nominations as defined in Section D.

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(Continued)



G. Operational Flow Orders and Emergency Flow Orders 1. Operational Flow Order (OFO)

a. The Utility System Operator’s protocol for declaring an Operational Flow Order (OFO) is described in Rule No. 41. All OFO declarations will be identified by stage that will specify a Daily Imbalance Tolerance and Noncompliance Charge per the table below. The daily balancing standby rate is not applicable to High OFOs.

Stage Daily Imbalance

Tolerance Noncompliance Charge ($/therm)

1 Up to +/-25% 0.025 2 Up to +/-20% 0.10 3 Up to +/-15% 0.50 4 Up to +/-5% 2.50 5 Up to +/-5% 2.50 plus Rate Schedule G-IMB daily balancing

standby rate EFO Zero 5.00 plus Rate Schedule G-IMB daily balancing

standby rate

b. The OFO shall apply to all customers financially responsible for managing and clearing transportation imbalances (Balancing Agents), including wholesale customers, Contracted Marketers, core aggregators, California Gas Producers and the Utility Gas Procurement Department.

c. The OFO period shall begin on the flow date(s) indicated by the Utility Gas Control

Department. Generally an initial OFO event will start at Stage 1; however an OFO event may begin at any stage as deemed appropriate by the Utility Gas Control Department with the corresponding noncompliance charge.

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(Continued)



G. Operational Flow Orders and Emergency Flow Orders (Continued) 1. Operational Flow Order (OFO) (Continued)

d. An OFO will normally be ordered with at least twelve (12) hours notice prior to the beginning

of the gas day, or as necessary as dictated by operating conditions. Charges for the first day of the OFO event will not be imposed if notice is given after 8:00 p.m.* Pacific Time the day prior to the start of the OFO event.

e. OFO and EFO compliance and charges will be based on the following for determination of

daily usage quantities:

i. For a Noncore End-Use Customer equipped with automated meter reading device (AMR) and SDG&E’s Electric & Gas Fuel Procurement Department, compliance during an OFO will be based on actual daily metered usage, and the calculation after the OFO event of any applicable noncompliance charge will be based on actual daily metered usage.

ii. For a Noncore End-Use Customer with non-functioning AMR meters, compliance

during an OFO or EFO will be based on the Customer’s actual daily metered usage; or the estimated daily usage in accordance with Section C of SoCalGas Rule 14 will be substituted for the actual daily metered usage when actual metered usage is not available.

iii. For a Noncore End-Use Customer without AMR capability compliance during an OFO

or EFO will be based on the Customer’s MinDQ. iv. For the Utility Gas Procurement Department, the Daily Forecast Quantity will be used as

a proxy for daily usage. v. For core aggregators, their Daily Contract Quantity will be used as a proxy for daily

usage. vi. For a California Producer with an effective California Producer Operational Balancing

Agreement, Form 6452, compliance with an OFO and EFO and calculation of any noncompliance charges will be based on the difference between scheduled receipts and measured receipts for each day of an event. OFO and EFO compliance for a California Producer with an existing non- California Producer Operational Balancing Agreement, Form 6452 access agreement will be treated consistent with the terms of that access agreement.

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(Continued)



G. Operational Flow Orders and Emergency Flow Orders (Continued) 1. Operational Flow Order (OFO) (Continued)

f. If a Balancing Agent’s OFO daily gas imbalance exceeds the applicable daily imbalance tolerance

by 10,000 therms or less, the OFO, noncompliance charge will be zero. If the daily gas imbalance amount exceeds the daily imbalance tolerance by more than 10,000 therms, the Balancing Agent will be responsible for the full noncompliance charge; i.e. 10,000 therms will not be deducted from the daily gas imbalance that exceeds the daily imbalance tolerance.

g. The daily measurement quantity used to calculate the Noncompliance Charge for each OFO

event will be the daily quantity recorded as of the month-end close of the applicable month. h. Low OFO noncompliance charges for the gas flow day will be waived when the confirmation

process limiting nominations to system capacity cuts previously scheduled BTS nominations during any of the Intraday 1-3 Cycles.*

i. SoCalGas will have the discretion to waive OFO noncompliance charges for an electric

generation customer who was dispatched after the Intraday 1 (Cycle 3) nomination deadline in response to (1) a SoCalGas System Operator request to an Electric Grid Operator to reallocate dispatched electric generation load to help maintain gas system reliability and integrity, or (2) an Electric Grid Operator request to the SoCalGas System Operator to help maintain electric system reliability and integrity that can be accommodated by the SoCalGas System Operator at its sole discretion. For electric generators served by a contracted marketer, OFO noncompliance charges can be waived under this section only to the extent the contracted marketer nominates their electric generation customer’s gas to the electric generation customer’s Order Control Code.*

2. Emergency Flow Order (EFO)

a. The Utility System Operator’s protocol for declaring an Emergency Flow Order (EFO) is described in Rule No. 41.

b. During an EFO Customer usage must be less than or equal to scheduled supply for a gas day.

EFOs will have a zero percent tolerance and a noncompliance charge of $5.00 plus the Schedule G-IMB Daily Balancing Standby Rate for each therm of usage in excess of scheduled supply.

c. The EFO shall apply to all customers financially responsible for managing and clearing

transportation imbalances (Balancing Agents), including wholesale customers, Contracted Marketers, core aggregators, California Gas Producers and the Utility Gas Procurement Department.

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(Continued)



G. Operational Flow Orders and Emergency Flow Orders (Continued)

2. Emergency Flow Order (EFO)

d. When an EFO is in effect interruptible storage withdrawals are limited to one half of the capacity normally available for interruptible withdrawals. Interruptible storage withdrawal capacity is equal to Withdrawal Capacity minus confirmed firm storage withdrawal nominations minus withdrawal allocated to the balancing function.

e. Daily measurement quantities used to determine EFO compliance and charges are the same as

those used to determine OFO compliance and charges. f. The daily measurement quantity used to calculate the noncompliance charges for each EFO

event will be the daily quantity recorded as of the month-end close of the applicable month. 3. Information regarding the System Sendout, Withdrawal Capacity and Net Withdrawals will be made

available to customers on a daily basis via the EBB. 4. If a wholesale customer so requests, the Utility will nominate firm storage withdrawal volumes on

behalf of the customer to match 100% of actual usage assuming the customer has sufficient firm storage withdrawal and inventory rights to match the customer's supply and demand.

5. The Utility will accept intra-day nominations to increase deliveries. 6. In all cases, current rules for monthly balancing and monthly imbalance trading continue to apply.

Quantities not in compliance with the Daily Imbalance Tolerance that are purchased at the daily balancing standby rate are credited toward the monthly 92% delivery requirements. Daily balancing charges remain independent of monthly balancing charges. Noncore daily balancing and monthly balancing charges go to the Purchased Gas Account (PGA). Net revenues from core daily balancing and monthly balancing charges go to the Noncore Fixed Cost Account (NFCA). Schedule No. G-IMB provides details on monthly and daily balancing charges.

H. Accounting and Billing 1. The customer and the Utility acknowledge that on any operating day during the customer's applicable

term of transportation service, the Utility may be redelivering quantities of gas to the customer pursuant to other present or future service arrangements. In such an event, the Utility and customer agree that the total quantities of gas shall be accounted for in accordance with the provisions of Rule No. 23. If there is no conflict with Rule No. 23, the quantities of gas shall be accounted for in the following order:

a. First, to satisfy any minimum quantities under existing agreements.

D D

Page 15



(Continued)


ADVICE LETTER NO. 5064 Dan Skopec DATE FILED Dec 1, 2016DECISION NO. Vice President EFFECTIVE Dec 1, 201628C9 Regulatory Affairs RESOLUTION NO.

M. Warranty and Indemnification 1. The customer warrants to the Utility that the customer has the right to deliver gas hereunder and that

such gas is free from all liens and adverse claims of every kind. Customer will indemnify, defend and save the Utility harmless against all loss, damage, injury, liability and expense of any character where such loss, damage, injury, liability or expense arises directly or indirectly out of any demand, claim, action, cause of action or suit brought by any person, association or entity asserting ownership of or any interest in the gas tendered for transportation hereunder, or on account of royalties, payments or other charges applicable before or upon delivery of gas hereunder.

2. The customer shall indemnify, defend and save harmless the Utility, its officers, agents, and

employees from and against any and all loss, costs (including reasonable attorneys' fees), damage, injury, liability, and claims for injury or death of persons (including any employee of the customer or the Utility), or for loss or damage to property (including the property of the customer or the Utility), which occurs or is based upon an act or acts which occur while the gas is deemed to be in the customer's control and possession or which results directly or indirectly from the customer's performance of its obligations arising pursuant to the provisions of its service agreement and the Utility's applicable tariff schedules, or occurs based on the customer-owned gas not meeting the specifications of Sections I or J of this rule.

N. OFO Trading*

1. Trading Scheduled Quantities*

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

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

c. Trades will only be available for OFO days. d. Trades must be submitted to the Utility’s scheduling department via email or fax by 9 PM Pacific

Clock Time one business day following the Gas Day for which the OFO was declared. e. The Utility may file an expedited Tier 2 Advice Letter to suspend this tariff provision if

curtailments are more severe or more frequent due to the offering of this service. Protests and responses to any such Advice Letter would be due within 5 business days, and the Utility’s reply would be due within 2 business days from the end of the protest period.

L N | | | | | | | | | | | | | N

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(Continued)


ADVICE LETTER NO. 5228 Dan Skopec DATE FILED Dec 1, 2017DECISION NO. D.17-11-021 Vice President EFFECTIVE Dec 1, 201729C5 Regulatory Affairs RESOLUTION NO.

N. OFO Trading* (Continued)

2. Trading Daily Imbalances*

a. California Producer cash-outs on OFO days will be delayed until 9:00 p.m. Pacific Clock Time one business day following the Gas Day pending submittal of the imbalance trade. If the imbalance is not traded, it will be cashed out.

b. California Producers may arrange to trade daily OFO imbalances with other California Producers. The trades are to be arranged outside of the EBB and communicated to the Utility via a trade form after Cycle 6 has been processed.

c. Trades will only be available for OFO days. d. Trades must be submitted to the Utility’s scheduling department via email or fax by 9 PM Pacific

Clock Time one business day following the Gas Day for which the OFO was declared. e. The Utility may file an expedited Tier 2 Advice Letter to suspend this tariff provision if

curtailments are more severe or more frequent due to the offering of this service. Protests and responses to any such Advice Letter would be due within 5 business days, and the Utility’s reply would be due within 2 business days from the end of the protest period.

O. Temporary Settlement Term

1. The Sections of this Rule italicized and followed by an asterisk (*) are temporary and will end upon the expiration of the term in the settlement approved by D.16-12-015 and modified by D.17-11-021. Specifically, that settlement term will conclude upon the earlier of: (1) any superseding decision or order by the Commission, (2) return of Aliso Canyon to at least 450 MMcfd of injection capacity and 1,395 MMcfd of withdrawal capacity, or (3) November 30, 2018.

T T

Page 17

Attachment Y: A.17-10-007, SCG-19R, Testimony of Michael

Baldwin, excerpts

317235

Company: Southern California Gas Company (U 904 G) Proceeding: 2019 General Rate Case Application: A.17-10-_____ Exhibit: SCG-19

SOCALGAS

DIRECT TESTIMONY OF MICHAEL H. BALDWIN

(CUSTOMER SERVICES - OFFICE OPERATIONS)

October 6, 2017


Page 1

MHB-73

currently in use at Sempra companies can be leveraged to improve ongoing 1

testing efforts; and 2

Complex software distribution management process currently in place to support 3

the fat client architecture will be simplified. Currently a software image is 4

individually distributed to over 2,500 workstations each time a software 5

enhancement is required. A new, thin client architecture allows a single image to 6

be posted to a small number of dedicated servers and can be done swiftly, with 7

increased reliability, and lower associated costs. 8

The specific details regarding the CIS Front-end Replacement Project cost can be found 9

in Mr. Olmsted’s capital workpapers (Ex. SCG-26-CWP, WP 00774Y – 19128 CIS Front-end 10

Replacement). 11

9. ICDA Phase 1 and 2 12

The forecast for ICDA for 2017, 2018, and 2019 are $520,000, $0 and $0, respectively. 13

The goal of this project is to enable SoCalGas to use customer data to make smarter, 14

faster, and better-informed decisions. ICDA will allow us to develop our capabilities, transform 15

our operations and target business outcomes across five major customer service business areas: 16

1) Billing and Collections; 17

2) Customer Usage; 18

3) Customer Analytics (Programs); 19

4) Consumption Forecasting; and 20

5) Customer Service Orders (CSO). 21

ICDA is a strategic priority and enabler of multiple projects within the Customer Services 22

and Customer Solutions organizations. ICDA’s goal is to develop data analytics capabilities 23

(people, technology and process) that enable the future vision of SoCalGas’ customer analytics. 24

The technology solution accommodates platforms, tools and various sources of customer data, 25

increased data volume generated from Advanced Meter interval data, customer self-service 26

transactional data and external third-party data. Data Analysts, Data Scientists and Data subject-27

matter-experts (people) will use data to analyze customer behavioral patterns, trends, and 28

preferences during the customer evolution process (starting service, requesting service orders, 29

program participation, remittance processing, transferring services, among others). Integrated 30

data will be leveraged for: 31

Page 2

MHB-74

1) Operational and monitoring purposes in the form of self-service reports and 1

dashboards; 2

2) Exploratory and discovery purposes to gain insights from the data, identify 3

patterns and develop models for future operationalization; and 4

3) Operationalization (actionable) implementation of models with transactional 5

systems. 6

The project will continue to develop and enforce its Data Governance and Data Analytics 7

lifecycle frameworks (processes) to develop data analytics capabilities at SoCalGas. 8

The specific details regarding the ICDA Project cost can be found in Mr. Olmsted’s 9

capital workpapers (Ex. SCG-26-CWP, WP 00784H – 81470 Integrated Customer Data & 10

Analytics). 11

10. FOF – Integrated Customer Data & Analytics (ICDA) Phase 3 12

The forecast for FOF – ICDA Phase 3 for 2017, 2018, and 2019 are $1,545,000, 13

$534,000 and $0, respectively. 14

The objective of this project is to continue the enhancement of the ICDA with three key 15

data analytics themes: 16

1. Customer Consumption Profiles – identify customer consumption patterns to be 17

applied throughout multiple use cases; 18

i. Leaking water heater 19

ii. BBQ left on 20

iii. Yard line leak 21

2. Collections Bad Debt Drivers - determine factors having most influence on bad 22

debt; 23

i. Enables targeted strategies to reduce bad debt (reduced bad debt which 24

benefits all rate payers). 25

3. Propensity model for Self Service indicates the likelihood of a particular customer 26

to respond to a targeted marketing strategy (e.g., Marketing paperless communication to area 27

identified through propensity model). 28

Having these analytical data attributes will enable data analysts to drill down into 29

problem areas, identify root causes, initiate actions to mitigate problems, and measure the results 30

of the action. 31

Page 3

MHB-75

The specific details regarding the FOF – ICDA Phase 3 Project costs can be found in Mr. 1

Olmsted’s capital workpapers (Ex. SCG-26-CWP, WP 007784C – 19110 FOF – ICDA Phase 3). 2

VII. CONCLUSION 3

Customer Services - Office Operations (CSOO) O&M and Capital project justifications 4

were carefully developed and reviewed, and represent a projection of the level of funding 5

necessary to support SoCalGas’ customer service and safety focus for the GRC term. Certain 6

requested increases in costs are necessary to achieve the forecasted efficiency reductions. 7

In summary, these forecasts reflect sound judgment to continuously support and enhance 8

the safe and efficient operation of the SoCalGas CSOO business unit at a reasonable cost. The 9

Commission should adopt the forecasted expenditures discussed in this testimony because they 10

are prudent and reasonable. 11

This concludes my prepared direct testimony. 12

13

Page 4

Attachment Z: SoCalGas Ninth Annual Report of System Reliability

Issues, April 24, 2018

Ninth Annual Report of System Reliability Issues 2018 Customer Forum

April 24, 2018

Page 1

Ninth Annual Report of System Reliability Issues

Date Issued: April 24, 2018

Page 2 of 6

Introduction SoCalGas presents its Ninth Annual Report of System Reliability Issues (Report). This Report covers the time period from April 1, 2017, through March 31, 2018. Pursuant to Section 23 of Rule No. 41, this Report provides information on the following matters:

A. Review of the timing, method, formulas, and all inputs to formulas by which OFO events are triggered;

B. Review of requests for the Operational Hub to acquire additional supplies to meet minimum

flow requirements;

C. Review of Operational Hub purchases/actions to meet minimum flow requirements and plans for the coming year by providing information regarding the individual transactions, including transactions executed pursuant to the Operational Hub contractual arrangements. Transaction‐specific information shall identify price, volume, date, delivery/receipt points, and any special terms;

D. Review the need for any additional minimum flow requirements on the Utility system beyond

then‐current defined requirements; and

E. Review potential additional tools to support system operations and potential system improvements to reduce or eliminate the need for any minimum flowing supply requirements.

Page 2



Page 3 of 6

A. Operational Flow Orders A High OFO may be issued if the level of scheduled quantities specified from Rule No. 41 in the table below for each transportation nomination cycle exceeds the forecasted system capacity.

Cycle Quantity Used for High OFO Calculation

1) Timely Prior Flow Day – Evening Cycle Scheduled Quantity

2) Evening Current Flow Day – Timely Cycle Scheduled Quantity

3) Intraday 1 Current Flow Day – Evening Cycle Scheduled Quantity

4) Intraday 2 Current Flow Day – Intraday 1 Cycle Scheduled Quantity

5) Intraday 3 Current Flow Day – Intraday 2 Cycle Scheduled Quantity

Forecasted system capacity is the sum of forecasted sendout, physical storage injection capacity and off‐

system scheduled quantities.

Gas Control develops the sendout forecast by using weather data for estimating core demand

(wholesale and retail) and market information and historical data for noncore customer demand

provided by the Customer Strategy and Engagement Department. Gas Control also makes use of

demand forecast data provided directly from the grid operators, including, but not limited to the

California Independent System Operator (CAISO), Los Angeles Department of Water & Power and

Imperial Irrigation District.

A total of 112 High OFO events were called from April 1, 2017 through March 31, 2018. In the previous

Report period, 98 High OFOs were called. Attachments 1A and 1B provide detailed calculations for each

High OFO event including calculations of forecasted system capacity in comparison to scheduled

quantities.

High OFO events are triggered when scheduled quantities from a previous cycle exceed forecasted

system capacity for a pending cycle. Most of the High OFOs called during a typical Report period occur

during the shoulder months when mild temperatures are prevalent.

Number of High OFOs from April 2017 through March 2018 Apr‐17 May‐17 Jun‐17 Jul‐17 Aug‐17 Sep‐17 Oct‐17 Nov‐17 Dec‐17 Jan‐18 Feb‐18 Mar‐18

13 13 16 14 10 4 9 19 5 6 1 2

Page 3



Page 4 of 6

A Low OFO will be issued if, on a day prior to this Gas Day, in the sole judgment of Gas Control, the

system forecast of storage withdrawal used for balancing exceeds the withdrawal capacity allocated to

the balancing function. Should SoCalGas’ implementation of a Low OFO prove to be inadequate to

ensure system integrity, SoCalGas may implement other measures including implementing an

Emergency Flow Order (EFO). SoCalGas may invoke EFOs when a forecast or an actual supply and/or

capacity shortage threatens deliveries to End‐Use Customers.

A total of 102 Low OFO events were called from April 1, 2017 through March 31, 2018. In the previous

Report period, 106 Low OFO events were called. Attachment 2 provides detailed calculations for each

Low OFO event for the Report period. Low OFO events were more prevalent during the colder winter

months.

Number of Low OFOs from April 2017 through March 2018 Apr‐17 May‐17 Jun‐17 Jul‐17 Aug‐17 Sep‐17 Oct‐17 Nov‐17 Dec‐17 Jan‐18 Feb‐18 Mar‐18 7 2 6 1 5 5 4 2 17 14 18 22

Pursuant to Decision (D.) 16‐12‐015, SoCalGas will implement the revised High OFO procedures

approved in D.16‐06‐039 on the first calendar day of the month that follows the month in which the

Aliso Canyon Turbine Replacement Project is placed into service and used for injection purposes. When

the revised High OFO procedures are implemented, a High OFO will be issued if, on a day prior to this

Gas Day, in the sole judgment of Gas Control, the system forecast of storage injection used for balancing

exceeds the injection capacity allocated to the balancing function. Similar to SoCalGas’ existing Low

OFO rules, there will be 5 stages of increasing noncompliance charges. For more information, see

SoCalGas Advice Letter 4997‐A.

B. Requests for Additional Supplies to Meet Minimum Flow Requirements A description of the requests from Gas Control for the Operational Hub to obtain additional supplies to meet Southern System minimum flow requirements from April 1, 2017 through March 31, 2018, can be found in Attachment 3. A total of 20 such requests were made during the Report period.

C. Operational Hub Transactions to Meet Minimum Flow Requirements and Plans for the Coming Year

Details of Operational Hub transactions to meet minimum flow requirements from April 1, 2017 through March 31, 2018 are provided in Attachment 4. These transactions are baseload and spot supply purchases and sales.

Page 4



Page 5 of 6

During the Report period SoCalGas purchased and sold approximately 12.2 MMDth of baseload supply

at an approximate net cost of 3 cents per Dth or a total approximate net cost of $0.3 million.

During the Report period SoCalGas also purchased and sold approximately 1.1 MMDth of spot market

supply at an approximate net cost of 55 cents per Dth or a total approximate net cost of $0.6 million.

During the Report period SoCalGas did not offer discounted interruptible transportation rates for gas

transported from the El Paso – Ehrenberg receipt point to increase customer delivery of gas into the

Southern System. Details of Southern System interruptible deliveries by month from April 1, 2017

through March 31, 2018 are provided in Attachment 5.

The total System Operator cost of meeting Southern System minimum flow requirements over the April

2017 through March 2018 period was $0.9 million; $0.3 million in Hub baseload purchases and $0.6

million in Hub spot purchases reflected in the System Reliability Memorandum Account (SRMA).

SoCalGas has taken several steps to address the Southern System minimum flow requirements.

For the 2017 summer season, from July 2017 through September 2017, SoCalGas entered 2 baseload gas

purchase agreements totaling 100 MDth/day. In August 2017, SoCalGas entered 3 additional baseload

gas purchase agreements totaling 100 MDth/day. These agreements satisfied summer baseload criteria

set forth in Rule No. 41.

The Fourth Memorandum in Lieu of Contract (MILC) between SoCalGas’ System Operator and Gas

Acquisition for gas supply to support Southern System minimum flow requirements became effective on

November 1, 2016. Its “evergreen” provision is limited to two one‐year terms ending not later than

October 31, 2018.

SoCalGas plans on continuing to use spot purchases, baseload agreements and to evaluate the possible

use of discounted BTS capacity over the next year to meet its Southern System minimum flow

requirements. Baseload purchase agreements were used during the Report period per the guidance

provided by the Commission for future baseload agreements in Resolution G‐3477. SoCalGas also hopes

to continue using agreements between the Utility System Operator and Gas Acquisition to support

SoCalGas’ minimum flow requirements on its Southern System for the coming year as well.

D. Need for Any Additional Minimum Flow Requirements There is no need for any additional minimum flow requirements outside of the Southern System at this time.

Page 5



Page 6 of 6

E. Potential Additional Tools to Support System Operations and Potential System Improvements to Reduce or Eliminate the Need for Minimum Flowing Supply Requirements

Potential Tools

Tools previously identified by SoCalGas to meet this minimum flow requirement include spot purchases,

Requests for Offers (RFOs) to gas suppliers to help meet Southern System flowing supply needs, and

minimum flow obligations, (See D.07‐12‐019, mimeo. at 58‐64.) and MILCs with Gas Acquisition.

On December 20, 2013 SoCalGas and SDG&E filed an application (A.13‐12‐013) for authority to recover

North‐South Project revenue requirement in customer rates, and for approval of related cost allocation

and rate design proposals. SoCalGas and SDG&E proposed the North‐South Project to help maintain

Southern System reliability and alleviate the potential for curtailments of customers on the Southern

System due to a potential mismatch between Southern System customer demand and the volume of

flowing supplies delivered to the Southern System to meet that demand. The Commission issued D.16‐

07‐015, rejecting the North‐South Project.

Rule No. 41 requires SoCalGas and Forum participants to collaborate in good faith to develop a post‐

Forum report that includes identifying any tariff changes that are found to be necessary by Forum

participants. Tariff changes proposed in the Forum will be submitted to the CPUC by Advice Letter no

later than 60 days after the Forum.

Joint Petition for Modification of Decision (D.) 16‐12‐015 Granted (D.17‐11‐021)

On September 8, 2017, SoCalGas, SDG&E, and 20 other parties filed a Joint Petition for Modification

(Joint PFM) of (D.) 16‐12‐015. The Joint PFM sought to extend the term of the Second Daily Balancing

Settlement from November 30, 2017 to November 30, 2018, subject to two other conditions that may

end the settlement term earlier. As it currently exists, the “settlement term will conclude upon the

earlier of: (1) any superseding decision or order by the Commission, (2) return of Aliso Canyon to at least

450 MMcfd of injection capacity and 1,395 MMcfd of withdrawal capacity, or (3) November 30, 2018.” A

similar Joint PFM was filed on February 16, 2017, which sought to extend the term of the Second Daily

Balancing Settlement from March 31, 2017 to November 30, 2017.

The Second Daily Balancing Settlement contains modifications to Schedule No. G‐IMB, Rule No. 30 and

Rule No. 41. These modifications were implemented in response to the operational constraints then in

existence at Aliso Canyon. Since operational constraints were believed to potentially continue beyond

the original settlement term, SoCalGas, SDG&E, and the 20 other parties petitioned for an extension of

the term through the upcoming summer injection season, subject to the conditions specified earlier.

Page 6

Attachment AA: SoCalGas Advice Letter 5275-A

[email protected]

Page 1

•

•

•

Page 2

•

and

See

Page 3

Page 4

and

Page 5

and

Page 6

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Release of Injection Capacity Reserved for Balancing:

Deferral of Projects that Impact Injection Operations:

Page 8

Page 9

See

Page 10

SeeSee also

Page 11

Page 12

Page 13

Page 14

CALIFORNIA PUBLIC UTILITIES COMMISSION ADVICE LETTER FILING SUMMARY

ENERGY UTILITYMUST BE COMPLETED BY UTILITY (Attach additional pages as needed)

Company name/CPUC Utility No. SOUTHERN CALIFORNIA GAS COMPANY (U 904G)Utility type: Contact Person: Ray B. Ortiz

ELC GAS Phone #: (213) 244-3837 PLC HEAT WATER E-mail: [email protected]

EXPLANATION OF UTILITY TYPE

ELC = Electric GAS = Gas PLC = Pipeline HEAT = Heat WATER = Water

(Date Filed/ Received Stamp by CPUC)

Advice Letter (AL) #: 5275-A

Subject of AL: Supplement - Expedited Advice Letter Requesting Approval of the Proposed Second Injection Enhancement Plan and Second Injection Enhancement Memorandum between the System Operator andthe Gas Acquisition Department for Services to Maintain Summer Reliability Pursuant to the March 13,2018 “Injection Required for SoCalGas Summer Reliability and Storage Inventories” Letter from CPUCExecutive Director Alice StebbinsKeywords (choose from CPUC listing): Storage, Agreements, Procurement, Contracts, Reliability AL filing type: Monthly Quarterly Annual One-Time Other If AL filed in compliance with a Commission order, indicate relevant Decision/Resolution #:NoneDoes AL replace a withdrawn or rejected AL? If so, identify the prior AL: No Summarize differences between the AL and the prior withdrawn or rejected AL1: N/A Does AL request confidential treatment? If so, provide explanation: No Resolution Required? Yes No Tier Designation: 1 2 3

Requested effective date: 3/13/18 No. of tariff sheets: 3 Estimated system annual revenue effect: (%): N/A Estimated system average rate effect (%): N/A When rates are affected by AL, include attachment in AL showing average rate effects on customer classes (residential, small commercial, large C/I, agricultural, lighting).Tariff schedules affected: Rule No. 41 and TOCs Service affected and changes proposed1: N/A Pending advice letters that revise the same tariff sheets: None

Protests and all other correspondence regarding this AL are due no later than 20 days after the date of this filing, unless otherwise authorized by the Commission, and shall be sent to: CPUC, Energy Division Southern California Gas Company Attention: Tariff Unit Attention: Ray B. Ortiz 505 Van Ness Ave., 555 West 5th Street, GT14D6 San Francisco, CA 94102 Los Angeles, CA 90013-1011 [email protected] [email protected]

[email protected]

1 Discuss in AL if more space is needed. Page 15

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2P5 Page 17

2P4 Page 18

1P4 Page 19

Page 20

SOCALGAS SECOND INJECTION ENHANCEMENT MEMORANDUM

Southern California Gas Company (SoCalGas), executes this Second Injection Enhancement Memorandum (Second IEM) to document the activities and direct the manner in which employees of SoCalGas, a public utility gas company regulated by the Public Utilities Commission of the State of California (CPUC), shall conduct the relationship between the SoCalGas System Operator1 and the Gas Acquisition Department (Gas Acquisition) to maximize storage injection to support system reliability, as directed by the CPUC.2 This Second IEM is in lieu of execution of a contract by SoCalGas (between the operating and functional departments within SoCalGas) to implement the CPUC’s directive.

1. Background.. On March 13, 2018, the Executive Director of the CPUC sent a letter to SoCalGas directing SoCalGas to file a Tier 2 Advice Letter “proposing an agreement between the SoCalGas System Operator and the SoCalGas Gas Acquisition Department to support SoCalGas’ storage requirements for system reliability similar to the Injection Enhancement Plan and Injection Enhancement Memorandum process approved by Resolution G-3529 (June 29, 2017).”

2. Proposed Injection Enhancement Plan Tools.. The CPUC directed SoCalGas’ Gas Acquisition Department to purchase natural gas to support SoCalGas’ storage requirement for system reliability.To facilitate increases to storage, the System Operator and Gas Acquisition will undertake actions as follows:Period:: The commencement date for the efforts addressed in this Second IEM is retroactive to March 13, 2018. The term of this Second IEM shall continue for each day from the commencement date through and including September 30, 2018.Support Activities:: Every month before Bid Week, the System Operator will set a portion of the storage injection capacity allocated to the system balancing function for injection nominations for the following month in Cycle 1. This quantity will be made available on a best efforts basis considering operational limitations and will be posted on Envoy. Gas Acquisition will use reasonable best efforts to utilize the quantity made available. The day before a gas flow day, the System Operator will determine whether additional injection capacity allocated to the system balancing function above what was made available for the month can be made available for injection nominations in Cycle1. If additional capacity can be made available for Cycle 1, the additional capacity will be reflected in the Net Storage Injection Capacity value on the Capacity Utilization Page on Envoy. The System Operator will use its reasonable best efforts to make this additional quantity available for the remainder of the gas day. Gas Acquisition will use its reasonable best efforts to utilize the quantity made available. Each flow day morning, the System Operator will determine whether additional injection capacity allocated to the system balancing function can be made available for injection nominations in Cycle 3. If additional capacity can be made available for Cycle 3, the additional capacity will be reflected in the Net Storage Injection Capacity value on the Capacity Utilization Page on Envoy. This additional

1 The System Operator is sometimes referred to internally as the “California Energy Hub” or the “Operational Hub.” 2 See March 13, 2018 letter from Alice Stebbins, Executive Director of the CPUC to Bret Lane, President and Chief Operating Officer of SoCalGas (“By this letter, I am directing SoCalGas to immediately begin maximizing storage injections at all storage fields using the procurement capabilities of the SoCalGas Acquisition Department to support SoCalGas' storage requirement for system reliability.”)

Page 21

quantity will be made available on a best efforts basis for the remainder of the gas day. Gas Acquisition will use reasonable best efforts to utilize the quantity made available. Costs:: Incremental costs associated with the Second IEM will be recorded in the Injection Enhancement Cost Memorandum Account.3

Regulatory approval:: This Second IEM will be submitted to the CPUC by Advice Letter and will not become effective until approved by the CPUC. In the event the CPUC does not approve this Second IEM, or imposes terms unacceptable to SoCalGas, this Second IEM will be null and void.

Based upon the foregoing, this Second IEM sets forth the commitment and guidelines by which employees of SoCalGas will interact to maximize storage injections to support system reliability, as directed by the CPUC. All such activity will be conducted in accordance with the terms and conditions of SoCalGas’ tariffs, and other applicable rules and regulations.

Date of execution: March 30, 2018

3 See Advice No. 5276, Expedited Advice Letter Requesting to Modify the Injection Enhancement Costs Memorandum Account (IECMA).

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Attachment AB: 2018 SoCalGas Customer Forum Presentation,

May 9, 2018

5/9/2018

May 9, 2018

2018 Customer Forum

Page 1

Agenda

• Introductions

• Antitrust Disclaimer

• High OFO Review

• Low OFO Review

• System Reliability Support Activity Results

• Post Forum Report / Next Steps

2

Page 2

Antitrust Disclaimer

3

Page 3

4

Page 4

5

Recording of

this Customer Forum

is prohibited

Page 5

High OFO Review

6

Page 6

High Operational Flow Order (High OFO)

• A High OFO is declared when SoCalGas determinesthat expected receipts will exceed total forecastedsystem capacity (including storage injection capacityand latest off‐system scheduled quantities) for apending flow day.

• SoCalGas uses the on‐system scheduled quantitiesfrom the latest scheduling cycle to determineexpected system receipts for the High OFOcalculation.

7

Page 7

Scheduled Quantities Used for High OFO

8

• On High OFO days, SoCalGas will confirm nominations up to the total net system capacity for Intraday 1 (Cycle 3), Intraday 2 (Cycle 4), and Intraday 3 (Cycle 5); [and during the Intraday 3 cycle when a High OFO event is not called and nominations exceed system capacity].

• SoCalGas will not declare a High OFO on Intraday 3 (Cycle 5), but will limit the confirmations to the total net system capacity as it does on all other days.

Cycle

Scheduled QuantityUsed for High OFO

Calculation

TimelyPrior Day,

Evening Cycle

EveningCurrent Day,Timely Cycle

Intraday 1Current Day,Evening Cycle

Intraday 2Current Day,

Intraday 1 Cycle

Intraday 3Current Day,

Intraday 2 Cycle

Page 8

High OFO Review: April 2017 – March 2018

• 112 High OFO events during Report Period.

• 14% increase compared to previous reporting period.

• High OFO procedures will change after the Aliso Canyon Turbine Replacement Project goes into service.

• TCAP Phase 1 Settlement condition.

• See SoCalGas Advice Letter 4997-A for tariff markup.

9

Page 9

High OFO Comparison

10

2017 Forum Report

Cycle 1 52Cycle 2 14Cycle 3 24Cycle 4 08

Total 98

2018 Forum Report

Cycle 1 27Cycle 2 28Cycle 3 37Cycle 4 20

Total 112

Page 10

Low OFO Review

11

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Low Operational Flow Order (Low OFO)

• A Low OFO is declared if, on a day prior to this Gas Day, in the sole judgment of Gas Control, the system forecast of storage withdrawal used for balancing exceeds the withdrawal capacity allocated to the balancing function.

12

Page 12

Low OFO Review: April 2017 – March 2018

13

Tolerance Percentages Declared• All Low OFOs were declared with a -5% Daily Imbalance

Tolerance.

Stages Declared• Stage 1 37• Stage 2 47• Stage 3 17• Stage 4 2

Total 103

Page 13

Low OFO Comparison

14

2017 Forum Report

Cycle 1 ‐‐‐Cycle 2 67Cycle 3 39Cycle 4 ‐‐‐

Total 106

2018 Forum Report

Cycle 1 ‐‐‐Cycle 2 72Cycle 3 31Cycle 4 ‐‐‐

Total 103*

*The Ninth Annual Report of System Reliability Issues (2018 Customer Forum Report) stated an incorrect count of 102.

Page 14

OFO Day Scheduled Quantity Adjustments• Scheduled quantities can be traded from one Balancing

Agent to another Balancing Agent for any OFO day.

• California Producer pools can trade scheduled quantities with other California Producer pools.

• A scheduled quantity adjustment (SQA) is not an imbalance trade.

• Imbalances are calculated at the end of the month by comparing billing quality meter usage to the final scheduled quantities for each day.

15

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OFO Day Scheduled Quantity Adjustments(Number of SQAs Processed)

16

‐

50

100

150

200

250

300

Number of SQ

As Processed

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17

‐

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

900,000

1,000,000

Total Sched

uled Quan

tities Processed

(dth)

OFO Day Scheduled Quantity Adjustments(Total Scheduled Quantities Processed)

Page 17

OFO Day Scheduled Quantity Adjustments• The OFO day SQAs are a time consuming, manual process.

• SQA requests for a given gas day must be submitted by both counterparties no later than 9 PM Pacific Time the next business day.

• Each Balancing Agent involved in an SQA must have a scheduled quantity in ENVOY.

• Each Balancing Agent must have at least a zero quantity nomination in order to implement an SQA for an OFO day.

• No nomination = No SQA.

• Adjustments into or out of storage contracts are not allowed.

18

Page 18

System Reliability Support Activity Results

19

Page 19

Southern System Reliability (SSR) Purchases and Interruptible BTS Discounts

20

2010‐2011

2011‐2012

2012‐2013

2013‐2014

2014‐2015

2015‐2016

2016‐2017

2017‐2018

Purchases (MDth) 1,045 3,015 16,989 42,879 31,311 33,309 45,349 13,354

Net Cost($/Dth) 3.63 0.36 0.37 0.36 0.13 0.10 0.20 0.07

SRMA Cost($MM) 3.8 1.1 6.3 15.5 4.1 3.3 9.1 0.9BTS

Discounts ($MM) 0 5.5 8.6 7.9 0.4 0 0.1 0

Total ($MM) 3.8 6.6 14.9 23.4 4.5 3.3 9.2 0.9

Page 20

21

Page 21

Post-Forum Report / Next Steps

22

Page 22

Post-Forum Report / Next Steps

• The Post-Forum Report will summarize the matters discussed here; identify action items, tariff changes, and procedural modifications that we agree are necessary; include descriptions of proposals presented by meeting participants.

• Any proposals made that are rejected by SoCalGas will be included in the Post-Forum Report.

• A draft Post-Forum Report will be issued to the Forum participants for review by May 30, 2018 with a revised draft to be issued by June 13, 2018.

• The Post-Forum Report will be filed by July 6, 2018.

23

Page 23

Storage Injection Enhancement Plan• Beginning on Gas Day April 9, 2018, portions of the storage injection

capacity allocated to the system balancing function have been available for nomination on Timely Cycle.

• The Net Storage Injection capacity will vary throughout the day based on the System Operation’s utilization of the system balancing injection capacity.

• The Net Storage Injection capacity will not fall below the capacity that was made available for Timely Cycle.

• See Advice Letter 5275-A for more details.

24

Page 24

Summer 2018 Outlook Summary• SoCalGas expects its current pipeline outages to extend through at

least the peak EG summer demand period.

• With these pipeline outages, SoCalGas will be challenged to fill storage inventory for the upcoming winter season.• Insufficient receipt capacity to both serve summer customer demand

and fill storage.

• Without the use of Aliso Canyon, SoCalGas can support a summer EG demand of 1.7 to 1.8 BCFD. With a total system capacity of 3.2 to 3.4 BCFD.

• Greater use of Aliso Canyon can mitigate curtailments and increase storage inventories in the other storage fields.

25

Page 25

2018 Summer “Peak” Demand ForecastCUSTOMER TYPE SUMMER DEMAND (BCFD)

Core 0.770

Noncore, Non‐Electric Generation 0.770

Noncore Electric Generation (EG) 1.971

Total 3.511

• Average core/non-EG noncore summer demand.

• SoCalGas EG demand forecast derived from 2017 peak summer demand.

• CAISO/LADWP technical assessment forecasts a minimum peak summer EG gas demand range of 1.4 to 1.8 BCFD depending on available import supplies and contingencies.

26

Page 26

SoCalGas Summer Receipt CapacityReceipt Point “Best Case” Supply

(MMcfd)“Worst Case” Supply

(MMcfd)

Blythe 1,010 800

Otay Mesa 200 150

North Needles 270 0

Topock 0 0

Kramer Junction 600 700

Wheeler Ridge / Kern River Station

765 765

California Production 60 60

Total Pipeline Receipts 2,905 2,475

Assume 85% Utilization 2,478 2,113

27

Page 27

SoCalGas Current System Outages

28

Page 28

Summer Storage Assessment (Non-Aliso)

• “Best Case” pipeline supplies allow for maintaining the IEP directive of 1,320 MMcfd of withdrawal through the summer.

• “Worst Case” pipeline supplies are insufficient for demand.• Non-Aliso fields are completely depleted of inventory in October.

• 95% receipt point utilization improves inventory, but 1,320 MMcfd of withdrawal cannot be maintained through the peak summer period.

29

0

5

10

15

20

25

30

35

40

45

0

100

200

300

400

500

600

700

800

900

1000

1100

1200

1300

1400

6/1/2018 7/1/2018 8/1/2018 9/1/2018 10/1/2018 11/1/2018

Inventory (BCF)

Withdrawal Rate (M

MCFD

)

Best INV Worst INV Best WD Worst WD IEP WD REQ

Page 29

Maintaining Summer Energy Reliability• SoCalGas remains focused on increasing its storage inventory.

• Advice Letter 5275-A filed April 20, 2018 to further enhance storage injection capability to increase inventory.

• SoCalGas will continue to coordinate operations with CAISO and LADWP.

• SoCalGas will use OFOs and the Aliso Canyon Withdrawal Protocol which includes curtailments.

• Maintenance will continue to be scheduled during periods of low demand except for identified safety issues or regulatory requirements.

• SoCalGas is still reviewing the agencies’ technical assessment and has some concerns with regards to the assumptions and conclusions and the viability and practical implementation of the suggested mitigation measures.

30

Page 30

5/9/2018

Page 31

Attachment AC: A.17-10-007, SCG-13, Testimony of Devin

Zornizer, excerpts

Company: Southern California Gas Company (U 904 G)] Proceeding: 2019 General Rate Case Application: A.17-10-___ Exhibit: SCG-13

SOCALGAS

DIRECT TESTIMONY OF DEVIN ZORNIZER

(GAS CONTROL AND SYSTEM OPERATIONS/PLANNING)

October 6, 2017


Page 1

DKZ-24

contain technology that is outdated and no longer compatible with our IT infrastructure. 1

Therefore, these communication trailers will require a complete redesign and/or 2

replacement to support the emergency events in the field. Earlier in my non-shared cost 3

section (SoCalGas Emergency Services), I discussed the underlying emergency response 4

and preparedness policies for this item in justification of my sponsored cost. 5

2. High OFO_EFO TCAP ENVOY® 6

In Decision (D.)16-06-039 (Decision Addressing the Phase 1 Issues and the Joint 7

Motion to Adopt the Settlement Agreement) in A. 14-12-017, the Commission approved 8

SoCalGas’ request to seek, in its next general rate case, recovery of costs related to High 9

OFO information system enhancements.15 10

System enhancements were implemented in ENVOY® and in the Specialized 11

Contract Billing System (SCBS) to support compliance with proposed changes to 12

SoCalGas tariff G-IMB, Rule 30, and Rule 41. Enhancements and modifications 13

included changing SCBS billing logic to assess the new high operational flow order 14

compliance, to remove the previous buy-back logic, and to calculate and bill balancing 15

charges. Enhancements to ENVOY® included modification of affected reports, 16

monitoring pages, and noticing pages. Costs in 2017 will relate to the completion of the 17

enhancements and modifications. 18

3. Low OFO and EFO 19

In D.15-06-004, the Commission granted SoCalGas permission to implement 20

Low OFO and EFO procedures and establish the OFCMA to track the costs associated 21

with the implementation.16 The execution required substantial system enhancements in 22

ENVOY® and in the SCBS. These enhancements were necessary to support compliance 23

with proposed changes to SoCalGas tariff G-IMB, Rule 30, and Rule 41 and included 24

modifications to the SCBS billing logic to assess the new low and emergency operational 25

flow order compliance, to remove the previous winter balancing logic, and to calculate 26

and bill balancing charges. Enhancements to ENVOY® included modification of 27

15 See D.16-06-039 at 64 (OP 12). 16 See D.15-06-004 at 42-44 (OP 6-13).

Page 2

DKZ-25

affected reports, monitoring pages, and noticing pages. In my testimony below I provide 1

more information about the project and the reasonableness of the costs in the OFCMA. 2

4. ENVOY® Generation MA (Microservice Architecture) 3

The existing ENVOY® system was developed over many years and consists of 4

legacy coding, software architecture, and programing that has been piecemealed together 5

to effectuate and enforce regulatory changes. The result is a system that is difficult and 6

costly to modify and adjust in a new regulatory environment that changes rapidly. 7

SoCalGas proposes to replace the existing ENVOY® system from the ground up, 8

making the system more flexible and customer friendly, allowing it to adapt quickly to 9

regulatory changes and enhancing the customer experience. Modularizing the 10

architecture of ENVOY® will make it more configurable. The individual functions and 11

business rules that are processed in the system will be coupled loosely allowing for 12

individual updates and deployments, permitting Gas Scheduling to quickly and efficiently 13

comply with regulatory mandates. To improve customer experience, ENVOY® will 14

further enhance and optimize the mobile capabilities on multiple platforms. 15

Computational graphics and event driven architecture will be used to disseminate 16

information to the marketplace quickly and allow for complex computations to be 17

displayed interactively. By utilizing suggestive transactions, ENVOY® will predict and 18

display the results of customers’ actions allowing the customer to analyze the potential 19

outcome prior to committing to the transaction. 20

5. ENVOY® Next Generation 21

The SoCalGas ENVOY® Next Generation Project entails a fully revamped 22

interface and navigational menus, expanded to provide customers with up-to-date 23

information, additional data querying functions and reporting, additional accessibility 24

(neutral web browser use and mobile platforms), customizable account functions, and 25

stronger web security. These additional capabilities were developed based on input from 26

ENVOY® service users. The project is divided into multiple phases. Phase I of the 27

project was developed and implemented in 2016. Phase II and Phase III were developed 28

and implemented in 2017. Phase IV will be developed in the later part of 2017 and will 29

be implemented in early 2018. 30

Page 3

Attachment AD: Joint Agencies, Aliso Canyon Impact of Reliability:

Summer 2018

DOCKETED

Docket Number:

18-IEPR-03

Project Title: Southern California Energy Reliability

TN #: 223362

Document Title:

Aliso Canyon Impact on Reliability Summer 2018

Description: Joint agency presentation by the CPUC, Energy Commission, LADWP, and the California ISO for the May 8, 2018 IEPR Joint Agency Workshop on Energy Reliability in Southern California

Filer: Stephanie Bailey

Organization: California Energy Commission

Submitter Role:

Commission Staff

Submission Date:

5/7/2018 3:01:21 PM

Docketed Date:

5/7/2018

Page 1

Aliso Canyon Impact on Reliability:

Summer 2018

May 8, 2018

California Energy

CommissionCalifornia Public

Utilities Commission

Los Angeles Department

of Water and Power

Page 2

Purpose of the Summer 2018 Technical Assessment

• 5th in series of assessments jointly prepared by staff at the

CEC, CPUC, CAISO and LADWP (hydraulic modeling by

SoCalGas)

• Assess risk to electric generation given restricted

operations at Aliso Canyon and identify measures to

mitigate that risk

• Calculate minimum gas required for electricity generation

(“min gen”), not as plan to curtail

• Summer 2018 Assessment is posted in IEPR docket at: http://www.energy.ca.gov/2018_energypolicy/documents/index.html#05082018

– Comments due May 22

Page 2

Page 3

Assessment Covers Following Key Topics

• Update on SoCalGas system status

• Preliminary look at how the system largely avoided gas

curtailments and electricity outages to date – including

February 19 to March 6 curtailment event

• Ability to meet 1-in-10 year electricity demand peak day

and resulting surplus or shortage

• Storage inventory preview for winter

• New mitigation measures to reduce electricity outage risk

• Update on mitigation measure results to date

Page 3

Page 4

Overall: Base Case Sufficient But With More Outages

Generation faces Curtailment Risk

Page 4

(MMcfd) Summer 2018 BaseSummer 2018

Sensitivity (More Outages)

1-in-10 Electric Peak Day Gas Demand 3,511 3,511

1-in-10 Gas Demand at MinGen with N-1 3,114 3,114

Pipeline Capacity Available 2,655 2,525

Required Storage Withdrawal (from Hydraulic Model) 900 900

Supported Demand (from Hydraulic Model) 3,555 3,425

Surplus or Shortfall on 1-in-10 Electric Peak Day 44 -85

Surplus or Shortfall at MinGen with N-1 441 311*

December 31 Storage Inventory from Gas Balance (Bcf) 541 432

1 From Case A Gas Balance with pipeline capacity of 2,655 MMcfd2 From Case D Gas Balance with pipeline capacity of 2,480 MMcfd

* This surplus assumes 100% of electric transmission is available and utilized. It shrinks if reduced to 90% and by 85% becomes a shortfall.

Page 5

SoCalGas’ System Remains Impaired by Multiple Pipeline

Outages

• On October 1, Line 235-2 ruptured,

burning the outside of an excavated

section of Line 4000

• The rupture led to increased concerns

about Line 4000, which went down for

expedited maintenance

• Line 4000 partially returned to service

on December 22

• There is no estimate for when Line

235-2 will return to service

• Line 3000 remains out

• Line 2000 is reduced to 980 MMcfd

• May be more outages

Page 5

Page 6

Reduced Capacity on Line 2000, Outages or Potential

Outages on Lines 235, 3000, 4000 and 5000

Page 6

Page 7

Receipt Capacity into Both Zones Affected

Page 7

Page 8

Interagency Cooperation, Lower Demand and OFOs

Helped Limit Curtailments throughout 2016 and 2017

• Manageable demands, supported largely by cooperative weather

helped offset limited supply

• Low OFOs used frequently to maintain balance

• Notices, watches and other alerts when necessary

• Only 2 days with EG curtailment, until February 2018

• Constant monitoring and work between SoCalGas, CAISO and

LADWP to shift generation, use imports key

Page 8

Weather

Notice

Curtailment

Watch

Flex

Alert

SCG Request

to All

Customers

EG Load

CurtailmentLow OFO

Delayed

Work

Days > 3.2 Bcf

Summer 2016 3 3 42 6

Winter 2016-17 28 6 7 2 64 45

Summer 2017 11 10 4 26 10

Winter 2017 -18 8 15 14 77

LADWP,

CAISO

and SoCalGas

14

OFO Page 9

Daily Natural Gas Sendout (Demand) for Past Two Summers

Page 9

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

1-A

pr

15-A

pr

29-A

pr

13-M

ay

27-M

ay

10-J

un

24-J

un

8-J

ul

22-J

ul

5-A

ug

19-A

ug

2-S

ep

16-S

ep

30-S

ep

14-O

ct

28-O

ct

Syste

m S

endout (M

Dth

)

2016 2017

Stress Threshold

2016 Supported Demand

Page 10

Late Winter Cold with the Outages Caused Curtailment

• Avoided expected curtailments in

December and January due to warm

weather

• Cold spell February 18 through March 6

• CAISO and LADWP reduced gas burn

(i.e., curtailed)

• Withdrew from Aliso in few hours over six

days (total of 1.1 Bcf)

• Using Aliso as asset of last resort

reduced operating flexibility

• Lower inventory reduces withdrawal

capacity as field pressure declines as

illustrated

Page 10

3.2+ Bcf 4+ Bcf

Winter 2015 41 4

Winter 2016 45 3

Winter 2017 14 0

Storage Inventory

January 1 63.8

February 18 57.4

March 6 48.8

0

200

400

600

800

1000

1200

0 10 20 30 40 50 60

Resu

lting

With

draw

al Ra

te (B

cfd)

Storage Inventory (Bcf)

Page 11

Full Analysis of Cold Spell Impacts Remains Underway

• Preliminary review shows system receipts consistently less than

system demand

– Both daily AND hourly

– zero hours in which receipt point capacity on SoCalGas system

was fully utilized

– ~6 MDth was available in every hour = 144 MDth or ~140 MMcfd

• Expect more detailed findings from CPUC later

• LADWP and CAISO assessing cost impact to electricity users

• Other CPUC Report Updates Will Take Account of Winter 2018

experience

– 715 report

– Withdrawal Protocol

Page 11

Page 12

SoCalGas Citygate Prices Higher on Colder Days

Page 12

0

10

20

30

40

50

60

70

80

0

5

10

15

20

25

12-J

an

-18

19-J

an

-18

26-J

an

-18

02-F

eb

-18

09-F

eb

-18

16-F

eb

-18

23-F

eb

-18

02-M

ar-

18

09-M

ar-

18

16-M

ar-

18

23-M

ar-

18

30-M

ar-

18

06-A

pr-

18

Co

mp

os

tite

Tem

p (

°F)

Pri

ce (

$ p

er

MM

Btu

)

PG&E Citygate SoCal Border SoCalGas Citygate Composite Temp

Page 13

Overall Finding for Summer 2018: Risk Remains

Despite 24.6 Bcf at Aliso

Good News:

• Gas required for minimum

generation on 1-in-10 peak day

lower

Bad News:

• Continuing pipeline outages

• Uncertain physical system

mitigation

• “Supported Demand” is lower

Page 13

End Result: • Have to use storage more heavily this summer

• Cannot meet 1-in-10 electricity peak day with N-1 without gas from

storage

• Cannot meet it at all in sensitivity case with more outages

• Minimum generation appears achievable but is NOT recommended

to drop EG to “mingen” levels due to challenge of available supply

and transmission

• More OFOs likely

• Outlook for winter storage inventory uncertainPage 14

SoCalGas System Capacity is Impaired Due to Continuing

and New Pipeline Outages

• Gas system has lower capacity this summer because key pipelines

out of service– Pipeline capacity reduced by 255 – 860 MMcfd versus last summer

– Supported Demand reduced by 83 – 213 MMcfd versus last summer

• MinGen requirement reduced by 296 MMcfd versus last summer

• Pipeline Capacity is ~500 MMcfd lower than last summer

– Could improve with system mitigation

– Could be worse with more outages and limited or no system

mitigation

Page 14

Page 15

System Capacity UNCERTAIN Depending on Outages and

Mitigation Scenario

Page 15

Pipeline capacity reduced by 255 – 860 MMcfd compared to last summer.

Summer 2017 May 1Summer 2018

Pessimistic

Summer 2018

Optimistic

Summer 2018

Combined

2016 CA

Gas Report

MMcfd

Receipt Point

North Needles 800 270a 0 270a 0

1,590Topock* 0 0b 0 0b 0

Kramer Junction 550 550 550 625c 625

Ehrenberg 1,010 980 800 980 800

1,210d

Otay Mesa 0 30 150 230 230

Wheeler Ridge 765 765 765 765 765 765

CA production 60 60 60 60 60 310e

TOTAL Supply 3,185 2,655 2,325 2,930 2,480 3,875

Page 16

Maximum Supported Demand Varies Depending on

Outages and System Mitigations

Page 16Supported Demand is 83 – 213 MMcfd lower than last summer.

SUMMER 2017 SUMMER 2018

Base Case Base Case Sensitivity

DAYPEAK

HOURDAY

PEAK

HOURDAY

PEAK

HOUR

MMcfd MMcfh MMcfd MMcfh MMcfd MMcfh

Pipeline 3185 132.7 2655 110.6 2525 105.2

North Needles 800 33.3 270 11.3 0 0

Topock* 0 0.0 0 0 0 0

Kramer Junction 550 22.9 550 22.9 700 29.2

Ehrenberg 1010 42.1 1010 42.1 800 33.3

Otay Mesa 0 0.0 0 0 200 8.3

Wheeler Ridge 765 31.9 765 31.9 765 31.9

CA production 60 2.5 60 2.5 60 2.6

Storage 468 61.3 900 55 900 55

Aliso Canyon 0 0.0 0 0 0 0

Honor Rancho 198 35.0 380 33.3 380 33.3

La Goleta 170 13.8 220 9.2 220 9.2

Playa del Rey 100 12.5 300 12.5 300 12.5

Supported Demand 3638 221.5 3555 214.7 3425 205.3Core 808 33.7 770 32.1 770 32.1

Electric Generation 2201 153.5 2015 151.6 1885 141.9

Noncore non-EG 629 34.3 770 31.0 770 31.3

Pack(+)/Draft(-) 15 -27.5 0 -49.1 0 -45.1

Page 17

Serving Supported Demand Uses More Storage This

Summer Due to Pipeline Outages

• Anytime demand > pipeline capacity, must use storage

• Achieving supported demand makes greater use of

storage than in previous summer: 468 vs. 900

• Substantial summer storage use reduces field inventories

• Expect more OFOs, both high and low

Page 17

SUMMER

2017

SUMMER

2018

MMcfd MMcfd

Storage 468 900

Aliso Canyon 0 0

Honor Rancho 198 380

La Goleta 170 220

Playa del Rey 100 300

Page 18

Summer 2018 Minimum Generation Requirement = 1,574 MMcfd

• Minimum Generation is the gas needed to prevent electricity service

outages and no more

• CAISO shifts generation to other units outside the SoCalGas service

area; LADWP needs imports from external entities to achieve

“MinGen”

• Departs from economic dispatch; increases cost of electricity

• Achievable only if

– all electric transmission lines operating at full capacity

– the replacement units have access to gas

• Calculations by CAISO and LADWP

• Last summer’s near 1-in-10 year peak day required 2,028 MMcfd

• “MinGen” gas requirement = 1,574 MMcfd

Page 18

Page 19

• Supported Demand is Lower but so Is EG Minimum Generation

• Results in increased cost to serve electric load

• Only feasible when sufficient external energy supplies are available

• Assumes 100% Electric Transmission is Available and Used

• Turns into a shortfall somewhere between 85 and 90 percent electric

transmission utilization at which point withdrawal from Aliso Canyon

may be necessary to avoid interruption to electric service

1-in-10 Demand Met When Electric Generation Reduced to

Minimum Generation

Page 19

Shortfall or Surplus on a 1-in-10 Peak Day with Minimum Electric Generation and an N-1 Contingency

(MMcfd) Assessment Group Base Case Assessment Group Sensitivity

1-in-10 Electric Peak Day Gas Demand 3,511 3,511

1-in-10 Year Customer Demand with Generation Curtailed to Minimum Levels

3,114 3,114

Supported Demand without Aliso Canyon 3,555 3,425

Gas System “Surplus” After Moving Electric Generation to Minimum

441 311

Page 20

Gas Balance Simulation Shows Range of Potential Storage

Inventory for Winter

Page 20

SoCalGas Monthly Gas Balance NORMAL WEATHER Summary

Case DescriptionSeptember

CapacityReserveMargin

Year-End Storage

Max Storage,Month

MMcf % Bcf Bcf

A Current Conditions 2655 0-10 54 70, July

A.30 Aliso increased to 30 Bcf 2655 0-10 59 75, July

B Additional Outages + 30 Bcf 2325 0-2 30 75, August

CCurrent Conditions + Mitigation and Aliso increased to 30 Bcf

2930 0-22 67 75, July

D Additional Outages + Mitigation 2480 0-11 43 70, July

D.30 D, with Aliso increased to 30 Bcf 2480 0-11 48 75, July

D. MaxD, with all pipeline capacity used to inject

2480 0% 69 96, August

• 7 cases testing different pipeline outages and system mitigation

• Fields reach maximum by July/August without violating parameters

• Reserve margins very low throughout

• December 31 storage inventory similar to last winter in most cases

• Higher inventory better to guard against cold-driven higher demand

Page 21

Update to Action Plan

Page 21

• 39 mitigation measures accumulated in prior Action Plans

• Many continue with no additional action

• Suggest 5 new measures for summer 2018:– Get 230 MMcfd for certain at Otay Mesa using LNG

– Fully utilize pipeline capacity by allowing SoCalGas to buy gas (i.e.,

expand Southern System Minimum procurement authority)

– Use existing rules to call high and low OFOs more frequently and together

when necessary

– Identify and expedite pending transmission upgrades with potential to

reduce MinGen requirement

– Monitor status of US Department of Energy NG demand response pilot

program to ensure California is a region for any pilots

• Work on plan for next winter unless outages remedied

soon Page 22

Prior Measures Implemented by CPUC

Page 22

Measure Note

Require SoCalGas to Use Aliso for Reliability Done

Tighter Gas Balancing and OFO Rules Done; may have

to extend

Efficiently Complete the Required Safety Review at Aliso Canyon to

Allow Safe Use of the Field

Done

Establish More Specific Gas Allocation among Generators in

Advance of Curtailment

Done

Determine if any Maintenance Can be Deferred and Still be Safe Done

Expand Gas and Electric Energy Efficiency (EE) Targeted at Low

Income Customers

Done

Expand Demand Response (DR) Programs Done

Reprioritize Existing EE Towards Programs with More Immediate

Impact

Extended through

2020

Reprioritize Solar Thermal Program Spending Done

Develop and Deploy Gas DR Program DonePage 23

CPUC-Estimated IOU Peak-Day Gas Demand Reductions

Resulting from Mitigation Measures & Others since 2010

Page 23


MMcfd

Gas Balancing Rules 536.5 72.3

Energy Efficiency 263.3 77.3

Energy Savings Assistance Program 6.8 2.5

California Solar Initiative: Thermal Program 0.9 0.9

Customer-Side Solar PV Electricity Generation 72.4 0

Marketing Education and Outreach NA NA

Electricity Storage 8 0

Electric Demand Response 63 0

Gas Demand Response NA NA

Total 950.8 153

These program reduced peak summer and winter gas demand by about 27% and 3%, respectively,

for SDG&E, SoCalGas and Southern California Edison. Page 24

CPUC Activities Beyond the Action Plan

• Updated the Aliso Canyon Demand-Side Resource Impact Report

http://www.cpuc.ca.gov/aliso/ and retitled “Aliso Canyon Mitigation

Measure Impacts Report.”

• In addition to the estimated Aliso Canyon mitigation measure

impacts, the CPUC estimated impacts of existing and authorized

demand-side resources that also reduce the demand for natural gas

in the region

• California Council for Science and Technology’s long-term study of

statewide viability of natural gas storage was released January 2018

• Order Instituting Investigation (I.17-02-002) into the feasibility of

reducing or eliminating use of Aliso Canyon is underway

• Updates to Section 715 report

Page 24

Page 25

http://www.cpuc.ca.gov/aliso/

CAISO Impact of Mitigation Measures

Page 25

• Proactive

coordination

between CAISO,

SoCalGas and

generators

demonstrates

success in reducing

gas imbalances.

• Enabling tariff

provisions expire

December 16, 2018

and may need

extension. Row Labels

Max Underscheduled2015



June 201 132 121July 227 105 154August 236 53 48September 224 129 66

Page 26

New Transmission Facilities in 2018 Summer Power Flow

• Santiago Substation Synchronous Condenser (243 MVar) in

service 12/8/2017 (SCE area)

• San Luis Rey Synchronous Condensers (450 MVAR) in service

12/29/2017 (SDG&E area)

• Sycamore – Penasquitos 230 kV line expected in service July

2018 (SDG&E area)

• These facilities help reduce the gas required at minimum

generation versus last summer.

Page 26

Page 27

Facilities Planned After Summer 2018 Will Also Help

• Three additional projects (previously planned) to improve

transmission facilities will strengthen Southern California energy

reliability and permit the electrical system to adjust more readily to

changing conditions:

– San Onofre Synchronous Condenser (240 MVAR) expected in

service by October 2018

– Suncrest Static VAR Compensator (300 MVAR) in service date

being revisited by project sponsor

– Mesa 230/500 kVLoop-In 500 kV line expected in service March

2022

Page 27

Page 28

LADWP Completed Mitigation Measure Estimated Impacts

Page 28

• Increase Electric and Gas Operational Coordination

– Improved coordination between utilities has increased LADWP’s

situational awareness, particularly during critical high heat days

• Update Physical Gas Hedging Practice

– Provides additional operational flexibility for LADWP in the event of gas

curtailments or curtailment watch periods

• Update Economic Dispatch Practice

– Provides additional operational flexibility and non-economic energy

purchases reduce reliance on local gas by 1.7 Bcf total gas burn

• Update Block Energy and Capacity Sales Practice

– Provides additional operational flexibility for LADWP in the event of gas

curtailments or curtailment watch periods

• Maintain Dual Fuel Capability

– 1,500 MW alternative fuel capability only as a last resort to maintain

electric reliability in emergency situations.

• Other actions highlighted in morning presentation Page 29

Comes Down to Outages, Balancing, and Weather -- Even

With Mitigation Measures

Page 29

• Risk to electric generation is larger this summer than last• The outages reduce pipeline capacity and Supported Demand

• By more than the decrease in 1-in-10 year demand

• Need system fully utilized before curtail generators

• Need demand < “Supported Demand”

• Need the pipeline system restored to full capacity

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Next Steps

• Continue monitoring closely:

– pipeline outages

– pipeline utilization

– storage inventory

– gas system mitigation success at Otay Mesa

– natural gas prices in Southern California

• Review and implement the additional mitigation

measures

• Comments Due May 22 to Energy Commission docket:

18 -IEPR-03–Southern California Energy ReliabilityPage 30

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Attachment AE: Aliso Canyon Withdrawal Protocol,

November 2, 2017

PUBLIC UTILITIES COMMISSION 505 VAN NESS AVENUE

SAN FRANCISCO, CA 94102-3298

Aliso Canyon Withdrawal Protocol

11.2.17

Introduction

Southern California Gas Company (SoCalGas) may withdraw gas from the Aliso Canyon natural

gas storage facility (Aliso Canyon) consistent with the protocol defined below. The protocol

implements the following principles:

Aliso Canyon will be treated as the “asset of last resort” used for withdrawals after

all other alternatives have been exhausted as defined by the protocol and consistent with items 1.A. and 1.B, below;

The priority of service under Southern California Gas Company Rule No. 23 shall remain in place should curtailments be required;

If curtailments are required, SoCalGas shall consult with the applicable Balancing Authorities (the California Independent System Operator [CAISO] and the Los Angeles Department of Water and Power [LADWP]) before and during any curtailment;

Should curtailments to electric generation create a risk to electric load that is critical to health and safety, withdrawals may be made consistent with the protocol; and

Withdrawals will be made in a manner that ensures safety, maintains the integrity of the wells and storage facility, and is consistent with all rules and regulations concerning the safe use of Aliso Canyon.

Aliso Canyon Withdrawal Protocol

1. Withdrawals from Aliso Canyon. Withdrawals from Aliso Canyon will be based on

forecasted and known conditions including but not limited to weather, overall gas demand,

electric generation gas demand, and the current and anticipated operating condition of the

SoCalGas system. Withdrawals will be made when, in coordination with the Balancing

Authorities, it is determined that withdrawals are necessary to maintain reliability overall, to

respond to a risk to electric system reliability, and/or to avoid or to limit curtailments to core and

noncore customers. In all cases, withdrawals may only be made consistent with safe operation of

the field and the system and in compliance with any mandated protocols for production from the

field.

Within this context, withdrawals will be made if the circumstances described in A or B, below,

occur:

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A. The following three conditions exist:

(1) SoCalGas has taken all appropriate actions it deems available and necessary to meet demand and to avoid curtailment of electric load and/or gas curtailments to core and noncore, non-electric generation customers. Such actions include the use of operational and emergency flow orders and coordination with Balancing Authorities to limit and/or reduce demand in effected areas; and

(2) To avoid curtailments of electric load, the CAISO and/or LADWP, in coordination with SoCalGas, have activated their appropriate capacity emergency plans based on the existing and forecast conditions; and

(3) There remains an imminent risk that curtailments of electric load will occur without additional gas supply.

B. There is an imminent and identifiable risk of gas curtailments created by an emergency condition that would impact public health and safety or result in curtailments of electric load that could be mitigated by withdrawals from Aliso Canyon. Such risk could arise due to emergencies on the gas pipeline system or because conditions require additional gas supply otherwise unavailable. Under such circumstances, when reliability is at risk and curtailment is imminent, SoCalGas may, at its sole discretion, execute a withdrawal from Aliso Canyon.

2. Readiness of the Aliso Canyon Field. SoCalGas shall take all actions necessary to allow for

timely withdrawals and shall maintain the Aliso Canyon field on a standby basis as warranted by

forecasted conditions/ risks to system reliability. Further, if at any time the CAISO declares a

Flex Alert, SoCalGas shall coordinate with the CAISO and LADWP and make any preparations

necessary to allow for a timely withdrawal.

3. Executing a Withdrawal Under Conditions Defined in 1.A. As operator of the Aliso

Canyon storage facility, SoCalGas has the obligation to make an informed decision to withdraw

gas from Aliso Canyon under the conditions defined in 1.A. above. In confirmation that those

conditions have been met, SoCalGas shall contact the Balancing Authorities and confirm that

they (the Balancing Authorities) have met the conditions in number 1.A. For information

purposes, the California Public Utilities Commission (CPUC) shall be included in such contacts

and may participate as appropriate.

Communications may be made using any method acceptable to SoCalGas, the CPUC, and the

Balancing Authorities. SoCalGas, the Balancing Authorities, and the CPUC shall make all

arrangements for the required communications and confirmations necessary with executing a

withdrawal.

4. Noticing and Reporting. SoCalGas shall immediately notify the CPUC Energy Division

(Energy Division) of the following: issuance of a Stage 4 or 5 Operational Flow Order or an

Emergency Flow Order; in the event of an emergency that threatens system reliability and may

require electric curtailments; and at the initiation of withdrawals from Aliso Canyon.

Within 24 hours of the cessation of a withdrawal from Aliso Canyon, SoCalGas shall provide the

Energy Division with the following:

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the total and hourly withdrawals from the field; the number of wells used for making withdrawals and the SoCalGas identifier for

each well used; the pre- and post-withdrawal Aliso working gas inventory; the hourly pipeline receipts for the calendar day(s) on which a withdrawal was

made and the day immediately preceding the withdrawal; the hourly withdrawals by field from non-Aliso storage facilities for the calendar

day(s) on which a withdrawal was made and the day immediately preceding the withdrawal;

information concerning any anomalies experienced during the operation of the field;

any repairs or mitigation required as a result of the withdrawal, including the time necessary to make them before another withdrawal could be made and the impact on the field’s injection and withdrawal capacity; and

whether the withdrawal was made under conditions identified in 1. B.

Within 30 days after a withdrawal, SoCalGas shall provide the Energy Division with a full

description of the events and conditions leading up to the withdrawal, all actions taken prior to

the withdrawal, and any observations or recommendations concerning the execution of future

withdrawals. Further, SoCalGas shall identify and describe any steps or actions not taken that

could have diminished or eliminated the need for a withdrawal and make comments and/or

recommendations for future consideration.

If a withdrawal from Aliso Canyon was due to an activation of the CAISO or LADWP

emergency plans as described in Section 1.A., the Balancing Authorities agree to submit a

description of the event that includes forecast demand, operating reserve requirements, and

anticipated capacity deficiencies based on the requested gas curtailments for the impacted hours.

The CAISO and/or LADWP may also:

a) identify and describe any steps or actions not taken that could have diminished or eliminated the need for a withdrawal, and

b) make comments and/or recommendations for future consideration.

5. Effective Date. This protocol shall become effective November 1, 2017. The protocol shall

remain in effect, subject to modification through the completion of the CPUC Investigation

(I.)17-02-002, or such time as determined based on conditions.

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Attachment AF: SoCalGas Rate Schedule G-BTS


Schedule No. G-BTS Sheet 1 BACKBONE TRANSPORTATION SERVICE


ADVICE LETTER NO. 4354 Lee Schavrien DATE FILED Mar 30, 2012DECISION NO. Senior Vice President EFFECTIVE May 1, 20121C6 RESOLUTION NO.

APPLICABILITY Applicable to firm and interruptible Backbone Transportation Service to Utility’s transmission system. Service under this Schedule is available to any creditworthy party. All eligible participants are collectively referred to herein as “customers” unless otherwise specified. Backbone Transportation Service rights to Utility’s transmission system neither guarantee nor imply firm service on Utility’s local transmission/distribution system; such service is defined by the end-use customers’ applicable Utility transportation service agreement.

TERRITORY

Applicable throughout the service territory. RECEIPT POINTS

Receipt Points available for service under this schedule are as follows: Total Transmission Zone Firm Access Specific Points of Access Transmission Zone (MMcfd) (MMcfd)* Southern 1210 EPN Ehrenberg - 1210 TGN Otay Mesa - 400 NBP Blythe - 600 Northern 1590 TW North Needles - 800 TW Topock - 300 EPN Topock - 540 QST North Needles - 120 KR/MP Kramer Junction – 550 Wheeler 765 KR/MP Wheeler Ridge – 765 PG&E Kern River Station - 520 OEHI Gosford – 150 Line 85 160 California Supply Coastal 150 California Supply Other N/A California Supply Total 3875

* Any interstate pipeline, LNG Supplier or PG&E that interconnect through a new receipt point may

be added to that Transmission Zone.

C

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Schedule No. G-BTS Sheet 2 BACKBONE TRANSPORTATION SERVICE

(Continued)


ADVICE LETTER NO. 4258 Lee Schavrien DATE FILED Jul 15, 2011DECISION NO. 11-03-029 Senior Vice President EFFECTIVE Oct 1, 20122C17 RESOLUTION NO.

RECEIPT POINTS (Continued)

EPN – El Paso Natural Gas Pipeline TGN – Transportadora de Gas Natural de Baja California NBP – North Baja Pipeline TW – Transwestern Pipeline MP – Mojave Pipeline QST – Questar Southern Trails Pipeline KR – Kern River Pipeline PG&E – Pacific Gas and Electric OEHI – Occidental of Elk Hills

Transmission Zone Contract Limitations:

Southern Zone – In total EPN Ehrenberg and NBP Blythe cannot exceed 1210 MMcfd. Southern Zone – In total EPN Ehrenberg, NBP Blythe and TGN Otay Mesa cannot exceed 1210 MMcfd. Northern Zone – In total TW at Topock and EPN at Topock cannot exceed 540 MMcfd. Northern Zone – In total TW at North Needles and QST at North Needles cannot exceed

800 MMcfd. Northern Zone – In total TW North Needles, TW Topock, EPN Topock, QST North

Needles, and KR/MP Kramer Junction cannot exceed 1590 MMcfd. Wheeler Ridge Zone – In total PG&E at Kern River Station and OEHI at Gosford cannot

exceed 520 MMcfd. Wheeler Ridge Zone – In total PG&E Kern River Station, OEHI Gosford, and KR/MP

Wheeler Ridge cannot exceed 765 MMcfd. DELIVERY POINTS

Delivery Points available for service under this schedule are:

1. End-User’s Local Transportation Agreement 2. Citygate Pool Account 3. Storage Account 4. Contracted Marketer or Core Aggregator Transportation Account

D

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Documents

Attachment B: Applicants’ Response to SCGC-01 excerpt€¦ · forecasts relative to estimated actual core usage. Please feel free to contact me if you have any questions regarding