EXHIBIT D

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COM/TAS/lil Date of Issuance 1/18/2012 

Decision 12-01-032 January 12, 2012 

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA 

Order Instituting Rulemaking to Revise and 

Clarify Commission Regulations Relating to the 

Safety of Electric Utility and Communications 

Infrastructure Provider Facilities. 

Rulemaking 08-11-005 

(Filed November 6, 2008) 

DECISION ADOPTING REGULATIONS TO REDUCE 

FIRE HAZARDS ASSOCIATED WITH OVERHEAD POWER LINES AND 

COMMUNICATION FACILITIES

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TABLE OF CONTENTS 

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DECISION ADOPTING REGULATIONS TO REDUCE FIRE HAZARDS 

ASSOCIATED WITH OVERHEAD POWER LINES AND 

COMMUNICATION FACILITIES.........................................................................1

1. Summary....................................................................................................................2

2. Background................................................................................................................5

2.1. Procedural Background................................................................................5

2.2. The Phase 2 Workshops ...............................................................................7

2.3. The Phase 2 Workshop Report and Briefs.................................................9

3. Commission Jurisdiction .......................................................................................10

4. Criteria for the Adoption of New Regulations ..................................................12

5. Consensus Proposals..............................................................................................14

5.1. Consensus Proposal 1 re: GO 95, Rule 18A............................................14

5.1.1. Summary of Proposal ...................................................................14

5.1.2. Position of the Parties ...................................................................14

5.1.3. Discussion.......................................................................................15

5.2. Consensus Proposal 2 re: GO 95, Rule 18B ............................................16

5.2.1. Summary of Proposal ...................................................................16

5.2.2. Position of the Parties ...................................................................17

5.2.3. Discussion.......................................................................................18

5.3. Consensus Proposal 3 re: GO 95, Rule 35...............................................19

5.3.1. Summary of Proposal ...................................................................19

5.3.2. Position of the Parties ...................................................................20

5.3.3. Discussion.......................................................................................21

5.4. Consensus Proposal 4 re: GO 95, Rule 37, Table 1, Case 14 and 

Footnotes (fff) - (jjj)......................................................................................22

5.4.1. Summary of Proposal ...................................................................22

5.4.2. Position of the Parties ...................................................................23

5.4.3. Discussion.......................................................................................23

5.5. Consensus Proposal 5 re: GO 95, Rules 23.0, 44.1, 44.2, and 44.3 .......24

5.5.1. Summary of Proposal ...................................................................24

5.5.2. Position of the Parties ...................................................................26

5.5.3. Discussion.......................................................................................26

5.6. Consensus Proposal 6 re: GO 165, Sections I - IV..................................27

5.6.1. Summary of Proposal ...................................................................27

5.6.2. Position of the Parties ...................................................................28

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5.6.3. Discussion.......................................................................................29

6. Contested Proposals...............................................................................................30

6.1. Contested Proposals 1A and 1B re: GO 95, Rule 11..............................31

6.1.1. Summary of Proposals..................................................................31

6.1.2. Position of the Parties ...................................................................31

6.1.3. Discussion.......................................................................................33

6.2. Contested Proposal 2 re: GO 95, Rule 12 and GO 165..........................34

6.2.1. Summary of Proposal ...................................................................34

6.2.2. Position of the Parties ...................................................................35

6.2.3. Discussion.......................................................................................35

6.3. Contested Proposals 3A and 3B re: GO 95, Rule 18A...........................36

6.3.1. Summary of Proposals..................................................................36

6.3.2. Position of the Parties ...................................................................38

6.3.3. Discussion.......................................................................................42

6.4. Contested Proposal 4 re: GO 95, Rule 18C .............................................45

6.4.1. Summary of Proposal ...................................................................45

6.4.2. Position of the Parties ...................................................................45

6.4.3. Discussion.......................................................................................48

6.5. Contested Proposal 5 re: GO 95, Rule 31.1 .............................................55

6.5.1. Summary of Proposal ...................................................................55

6.5.2. Position of the Parties ...................................................................56

6.5.3. Discussion.......................................................................................58

6.6. Contested Proposals 6A – 6D re: GO 95, Rules 31.2 and 80.1A ..........61

6.6.1. Summary of Proposals 6A and 6B ..............................................61

6.6.2. Summary of Proposals 6C and 6D..............................................62

6.6.3. Position of the Parties ...................................................................63

6.6.4. Discussion.......................................................................................71

6.7. Contested Proposal 6E re: GO 95, Rule 80.1B ........................................79

6.7.1. Summary of Proposal ...................................................................79

6.7.2. Position of the Parties ...................................................................80

6.7.3. Discussion.......................................................................................83

6.8. Contested Proposal 7A re: GO 95, Rule 35, Paragraph 4 .....................86

6.8.1. Summary of Proposal ...................................................................86

6.8.2. Position of the Parties ...................................................................86

6.8.3. Discussion.......................................................................................90

6.9. Contested Proposal 7B re: GO 95, Rule 35, Third Exception...............95

6.9.1. Summary of Proposal ...................................................................95

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6.9.2. Position of the Parties ...................................................................96

6.9.3. Discussion.......................................................................................98

6.10. Contested Proposal 8A re: GO 95, Appendix E.....................................99

6.10.1. Summary of Proposal ...................................................................99

6.10.2. Position of the Parties .................................................................100

6.10.3. Discussion.....................................................................................101

6.11. Contested Proposals 8B and 8C re: GO 95, Rule 35, Appendix 

E, Guidelines Only ....................................................................................102

6.11.1. Summary of Proposals................................................................102

6.11.2. Position of the Parties .................................................................104

6.11.3. Discussion.....................................................................................105

6.12. Contested Proposal 9 re: GO 95, Rule 38, Table 2, 

Footnote (aaa) ............................................................................................107

6.12.1. Summary of Proposal .................................................................107

6.12.2. Position of the Parties .................................................................108

6.12.3. Discussion.....................................................................................110

6.13. Contested Proposals 10A and 10B re: GO 95, Rule 44.2, 

Rule 44.4, and Appendix I .......................................................................111

6.13.1. Summary of Proposals................................................................111

6.13.2. Position of the Parties .................................................................113

6.13.3. Discussion.....................................................................................114

6.14. Contested Proposals 11A and 11B re: GO 95, Rule 48........................117

6.14.1. Summary of Proposals................................................................117

6.14.2. Position of the Parties .................................................................118

6.14.3. Discussion.....................................................................................120

6.15. Contested Proposal 12 re: GO 95, Rule 91.5 .........................................123

6.15.1. Summary of Proposal .................................................................123

6.15.2. Position of the Parties .................................................................124

6.15.3. Discussion.....................................................................................126

6.16. Contested Proposals 13A and 13B re: GO 165, Section V and 

Proposed Ordering Paragraph................................................................128

6.16.1. Summary of Proposals................................................................128

6.16.2. Position of the Parties .................................................................129

6.16.3. Discussion.....................................................................................132

6.17. Contested Proposals 14A, 14B, and 14C re: Fire-Threat Maps..........135

6.17.1. Summary of Proposals................................................................135

6.17.1.1 Summary of Contested Proposal 14A.................................136

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6.17.1.2 Summary of Contested Proposals 14B and 14C................137

6.17.2. Position of the Parties .................................................................138

6.17.3. Position of Cal Fire......................................................................141

6.17.4. Discussion.....................................................................................142

6.18. Record Retention .......................................................................................150

6.19. Commission Jurisdiction and Publicly Owned Utilities .....................150

6.20. Cost Recovery ............................................................................................151

6.20.1. Cost Recovery for Electric IOUs................................................153

6.20.2. Cost Recovery for the Small LECs ............................................154

6.21. Implementation .........................................................................................156

7. California Environmental Quality Act ..............................................................156

8. Proposed Rulemaking Proceeding re: Electric Tariff Rule 20.......................158

8.1. Background ................................................................................................158

8.2. Position of the Parties ...............................................................................160

8.3. Discussion...................................................................................................163

9. Need for Hearing..................................................................................................164

10. Comments on the Proposed Decision................................................................164

11. Assignment of the Proceeding............................................................................165

Findings of Fact.............................................................................................................165

Conclusions of Law ......................................................................................................168

ORDER ...........................................................................................................................174

Appendix A: Proposed Regulations ..................................................................... A-1

Consensus Proposal 1 re: GO 95, Rule 18A.........................................................A-2

Consensus Proposal 2 re: GO 95, Rule 18B .........................................................A-5

Consensus Proposal 3 re: GO 95, Rule 35............................................................A-6

Consensus Proposal 4 re: GO 95, Rule 37, Table 1, Case 14 

and Footnotes (fff) – (jjj)...................................................................................A-7

Consensus Proposal 5 re: GO 95, Rules 23, 44.1, 44.2, and 44.3 .......................A-9

Consensus Proposal 6 re: GO 165, Sections I – IV ............................................A-11

Contested Proposal 1A re: GO 95, Rule 11 (CPSD)..........................................A-17

Contested Proposal 1B re: GO 95, Rule 11 (CIP Coalition).............................A-17

Contested Proposal 2 re: GO 95, Rule 12 (CPSD).............................................A-17

Contested Proposal 3A re: GO 95, Rule 18 (CIP Coalition) ............................A-18

Contested Proposal 3B re: GO 95, Rule 18 (SDG&E) .......................................A-22

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Contested Proposal 4 re: GO 95, Rule 18C (MGRA)........................................A-26

Contested Proposal 5 re: GO 95, Rule 31.1 (Joint Utilities).............................A-26

Contested Proposal 6A re: GO 95, Rule 31.2 (CIP-1) .......................................A-28

Contested Proposal 6B re: GO 95, Rule 31.2 (CIP-2)........................................A-29

Contested Proposal 6C re: GO 95, Rule 31.2 and Rule 80.1 (CPSD)..............A-30

Contested Proposal 6D re: GO 95, Rule 31.2 and Rule 80.1 (SDG&E) ..........A-32

Contested Proposal 6E re: GO 95, Rule 31.2 and Rule 80.1B (CPSD)............A-34

Contested Proposal 7A re: GO 95, Rule 35, Paragraph 4 (Joint Utilities) .....A-35

Contested Proposal 7B re: GO 95, Rule 35, Exception 3 (Joint Utilities).......A-36

Contested Proposal 8A re: GO 95, Rule 35, Appendix E, Table 

(Joint Utilities).................................................................................................A-38

Contested Proposal 8B re: GO 95, Rule 35, Guidelines (Joint Utilities) ........A-38

Contested Proposal 8C re: GO 95, Rule 35, Guidelines (CFBF and 

MGRA).............................................................................................................A-39

Contested Proposal 9 re: GO 95, Rule 38, Table 2, Footnote (aaa) 

(Joint Utilities).................................................................................................A-39

Contested Proposal 10A re: GO 95, Rule 44.4 (CIP Coalition) .......................A-40

Contested Proposal 10B re: GO 95, Rule 44.2, Rule 44.4, and Appendix I 

(Joint Utilities).................................................................................................A-41

Contested Proposal 11A re: GO 95, Rule 48 (Joint Utilities)...........................A-43

Contested Proposal 11B re: GO 95, Section IV, 

Proposed Ordering Paragraph (CPSD).......................................................A-43

Contested Proposal 12 re: GO 95, Proposed Rule 91.5 (SDG&E)...................A-43

Contested Proposal 13A re: GO 165, Section V (CPSD and MGRA).............A-44

Contested Proposal 13B re: Proposed Ordering Paragraph 

on Data Collection (PG&E) ...........................................................................A-44

Contested Proposal 14A re: Proposed Ordering Paragraph Regarding 

Fire Maps (CPSD and MGRA) .....................................................................A-45

Contested Proposals 14A and 14B re: GO 95, Rule 31.2, 

Fire Maps for CIP Inspections ......................................................................A-46

Appendix B: Adopted Revisions to General Orders 95, 165, and 166 ............B-1

General Order 95, Rule 11....................................................................................... B-2

General Order 95, Rule 18A.................................................................................... B-3

General Order 95, Rule 18B .................................................................................... B-6

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General Order 95, Rule 23.0.................................................................................... B-6

General Order 95, Rule 31.1.................................................................................... B-7

General Order 95, Rule 31.2.................................................................................... B-8

General Order 95, Rule 35....................................................................................... B-9

General Order 95, Rule 35, Appendix E, Guidelines ........................................ B-11

General Order 95, Rule 35, Appendix E, Table.................................................. B-11

General Order 95, Rule 37, Table 1, Case 14 and Footnotes (fff) -(jjj)............. B-12

General Order 95, Rules 44.1, 44.2, 44.3.............................................................. B-13

General Order 95, Rule 44.4.................................................................................. B-14

General Order 95, Rule 80.1A............................................................................... B-15

General Order 95, Rule 80.1B ............................................................................... B-18

General Order 95, Rule 91.5.................................................................................. B-20

General Order 165, Sections I - IV........................................................................ B-21

General Order 166, Standard 1.E ......................................................................... B-26

Appendix C: Adopted Interim Fire-Threat Maps...............................................C-1

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DECISION ADOPTING REGULATIONS TO REDUCE FIRE HAZARDS ASSOCIATED

WITH OVERHEAD POWER LINES AND COMMUNICATION FACILITIES

1. Summary 

Today’s decision adopts regulations to reduce the fire hazards associated 

with overhead power lines and aerial communication facilities located in close 

proximity to power lines. The most significant regulations adopted by today’s 

decision are as follows: 

• Rule 18A of General Order (GO) 95 is revised to require electric 

utilities and communication infrastructure providers (CIPs) to 

correct within 12 months any Level 2 nonconformance that 

creates a fire hazard in a high fire-threat area of Southern 

California. 

• Rule 31.2 of GO 95 is revised to require CIPs to inspect their 

aerial facilities on the following cycles: 

i. Patrol inspections every year for facilities located in high 

fire-threat areas of Southern California, and every two 

years for facilities located in high fire-threat areas of 

Northern California. 

ii. Detailed inspections every five years for facilities located 

in high fire-threat areas of Southern California, and every 

10 years for facilities located in high fire-threat areas of 

Northern California. 

iii. The inspection requirements in Items (i) – (ii) apply to 

CIP facilities attached to joint-use poles and to CIP-only 

poles within three spans of a joint-use pole. 

iv. Intrusive inspections on the cycles set forth in GO 165 for 

CIP-only poles that are located within three spans of a 

joint-use pole in high fire-threat areas of Southern 

California, and within one span of a joint-use pole in high 

fire-threat areas of Northern California. 

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• Rule 35 of GO 95 is revised to (1) apply vegetation management 

requirements to electric utility facilities and CIP facilities located 

on lands owned by state and local agencies; (2) require electric 

utilities and CIPs to remove vegetation-related strain on 

conductors energized at 750 volts or less; and (3) allow electric 

utilities and CIPs to notify land owners who obstruct vegetation 

management that if a vegetation-related fire occurs, the 

company may seek to recover its fire-related costs from the land 

owner. 

• Rule 44.2 of GO 95 is revised to require pole-loading 

calculations whenever there is a material increase in load as 

defined by Ordering Paragraph 4 of Decision 09-08-029. 

Rule 44.4 is revised to require entities to share information 

needed for pole-loading calculations. 

• A new Rule 91.5 is added to GO 95 that requires CIPs to attach 

a marker to newly constructed and reconstructed CIP facilities 

on joint-use poles. The marker must identify the owner of the 

CIP facilities and provide contact information for the owner. 

• Appendix E of GO 95 is revised to (1) state that electric utilities 

and CIPs may exceed the recommended minimum time-oftrim vegetation clearances, and (2) provide a list of factors that 

electric utilities and CIPs should consider when deciding 

whether, and to what extent, to exceed the recommended 

minimum time-of-trim clearances. 

• A new Standard 1.E is added to GO 166 that requires investorowned electric utilities (electric IOUs) in Southern California to 

prepare and submit plans to prevent power-line fires during 

extreme fire-weather events. Electric IOUs in Northern 

California must make a good faith effort to determine if there is 

a credible possibility of extreme fire-weather events in their 

service territories and, if so, to prepare and submit plans to 

prevent power-line fires from occurring during such events. 

• Electric IOUs are authorized to revise their tariffs to state that 

the electric utility may shut off power to a property owner who 

obstructs access to the utility’s overhead power-line facilities 

located on the owner’s property for vegetation management 

purposes. This authority is limited to (1) situations where 

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vegetation has breached the minimum required clearances for 

bare-line conductors set forth in GO 95, Rule 35, Table 1, 

Cases 13 and 14; and (2) one meter serving the property 

owner’s primary residence, or if the property owner is a 

business entity, the entity’s primary place of business. This 

one meter is in addition to shutting off power at the location of 

the vegetation-related fire hazard. Prior to shutting off power, 

the electric utility must follow the notice requirements that are 

applicable to the discontinuance of service for non payment, 

including the notice requirements applicable for sensitive 

customers, customers who are not proficient in English, 

multifamily accommodations, and other customer groups. 

• A new Phase 3 of this proceeding is established to consider, 

develop, and adopt regulations regarding the following matters: 

(1) Revising Section IV of GO 95 to reflect modern materials and 

practices, with the goal of improving fire safety. (2) Revising 

Section IV of GO 95 to incorporate a new High Fire-Threat 

District and new standards for the design and construction of 

electric utility and CIP structures located in the new District. 

(3) Developing a plan for the Consumer Protection and Safety 

Division to collect data from electric IOUs regarding power-line 

fires and using this data to (a) identify and assess systemic 

fire-safety risks associated with overhead power-line facilities 

and aerial CIP facilities in close proximity to power lines, and 

(b) formulate cost-effective measures to reduce systemic firesafety risks. (4) Developing fire-threat maps. This last matter 

will include consideration of fire-threat maps developed by the 

CIP Coalition (the Reax Map), San Diego Gas & Electric 

Company (SDG&E), and other parties. The California 

Department of Forestry and Fire Protection (Cal Fire), Lawrence 

Livermore National Laboratory, and the parties to this 

proceeding are invited to participate in Phase 3. The final scope 

and schedule for Phase 3 will be set forth in the Assigned 

Commissioner’s scoping memo for Phase 3. 

• Until permanent fire-threat maps are adopted in Phase 3, the 

electric utilities and CIPs shall use, on an interim basis, the 

Reax Map, the SDG&E Map, and Cal Fire’s Fire Resource 

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Assessment Program Fire Threat Map to implement the 

fire-prevention measures adopted in this proceeding. 

The investor-owned electric utilities may file applications to recover the 

costs they incur to implement the regulations adopted in this proceeding until 

their next general rate case (GRC) proceedings. The electric utilities shall 

thereafter seek to recover such costs through the GRC process. Similarly, the 

Small Local Exchange Carriers may use their annual California High Cost 

Fund-A advice letters to recover the costs they incur to implement the 

regulations adopted in this proceeding until their next GRC proceedings. 

Finally, today’s decision denies the request by several parties to open a 

new rulemaking proceeding to consider if electric Tariff Rule 20 should be 

amended to add “fire risk” to the list of reasons to permit the undergrounding of 

aerial facilities pursuant to Tariff Rule 20. 

2. Background 

2.1. Procedural Background 

In October 2007, strong Santa Ana winds swept across Southern California 

and caused dozens of wildfires. The resulting conflagration burned more than 

780 square miles, killed 17 people, and destroyed thousands of homes and 

buildings. Hundreds of thousands of people were evacuated at the height of the 

fire siege. Transportation was disrupted over a large area for several days, 

including many road closures. Portions of the electric power network, public 

communication systems, and community water sources were destroyed.1 

 

1 California Fire Siege 2007 – an Overview prepared by the California Department of 

Forestry and Fire Protection, at page 6. We take official notice of this document on 

Footnote continued on next page 

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Several of the worst wildfires were reportedly ignited by power lines. 

These included the Grass Valley Fire (1,247 acres); the Malibu Canyon Fire (4,521 

acres); the Rice Fire (9,472 acres); the Sedgewick Fire (710 acres); and the 

Witch Fire (197,990 acres).2 The total area burned by these five power-line fires 

was more than 334 square miles. 

In response to the widespread devastation, the Commission issued Order 

Instituting Rulemaking (OIR) 08-11-005 on November 6, 2008, to consider and 

adopt regulations to reduce the fire hazards associated with overhead power-line 

facilities and aerial communication facilities in close proximity to power lines. 

On January 6, 2009, the Assigned Commissioner issued a ruling and scoping 

memo (“Scoping Memo”) that split this proceeding into two phases. The focus 

of Phase 1 was to adopt fire-prevention measures that could be implemented in 

time for the 2009 autumn fire season in Southern California. Phase 1 concluded 

with the issuance of Decision (D.) 09-08-029 (“the Phase 1 Decision”). 

A prehearing conference for Phase 2 was held on October 9, 2009. On 

November 5, 2009, the Assigned Commissioner issued the Phase 2 Scoping 

Memo that identified 25 topics as within the scope of Phase 2, including the issue 

of whether “fire risk” should be added to the list of reasons to permit 

undergrounding pursuant to electric Tariff Rule 20. 

The Phase 1 Decision directed that Phase 2 be conducted through a 

workshop process.3 To this end, the Phase 2 Scoping Memo established a 

 

our own motion pursuant to Pub. Util. Code §§ 701 and 1701, and Rule 13.9 of the 

Commission’s Rules of Practice and Procedure. 

2 California Fire Siege 2007 – an Overview, at pages 20, 27, and Appendix II. 

3 D.09-08-029 at 45 and Conclusion of Law 19. 

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framework for conducting the Phase 2 workshops, set a workshop schedule, and 

appointed Administrative Law Judges (ALJs) Angela Minkin and Jean Vieth to 

serve as neutral facilitators for the workshops. The Phase 2 Scoping Memo also 

directed the workshop participants to prepare and submit a workshop report 

containing proposals for reducing fire hazards. 

Parties were given an opportunity to request an evidentiary hearing 

regarding Phase 2 issues using the procedures in the Phase 2 Scoping Memo. 

There were no requests for an evidentiary hearing and none was held. 

2.2. The Phase 2 Workshops 

The first workshop for Phase 2 was held on January 15, 2010. In total, 

25 days of workshops were held over a period of six months. The workshop 

sessions were publicly noticed and open to the public. Thirty nine parties 

actively participated in the workshops, including Commission’s staff, 

investor-owned utilities, municipal utilities, telecommunications companies, 

a labor union, consumer groups, and independent consultants. The parties 

represented at the workshops are listed below: 

List of Phase 2 Workshop Participants 

Bill Adams 

AT&T California and New Cingular Wireless PCS, LLC (AT&T) 

The Commission‘s Consumer Protection Division (CPSD) 

The Commission‘s Division of Ratepayer Advocates (DRA) 

California Cable & Telecommunications Association (CCTA) 

California Department of Forestry and Fire Protection (Cal Fire) 

California Farm Bureau Federation (CFBF) 

California Independent System Operator Corporation (CAISO) 

California Municipal Utilities Association (CMUA) 

California Association of Competitive Telecommunications Carriers (Cal Tel) 

Frontier Communications of California (Frontier) 

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List of Phase 2 Workshop Participants 

CTIA-The Wireless Association (CTIA) 

Comcast Phone of California, LLC (Comcast) 

County of Los Angeles Fire Department (LA County) 

CoxCom Inc. and Cox California Telecom, L.L.C. (Cox) 

Davey Tree 

Extenet 

Facilities Management Specialists, LLC 

International Brotherhood of Electrical Workers 1245 (IBEW 1245) 

Los Angeles Department of Water and Power (LADWP) 

Mussey Grade Road Alliance (MGRA) 

NextG Networks of California, Inc. (NextG) 

Northern California Power Association 

Osmose Utilities Services 

Pacific Gas and Electric Company (PG&E) 

PacifiCorp 

Sacramento Municipal Utility District (SMUD) 

San Diego Gas & Electric Company (SDG&E) 

Sierra Pacific Power Company (Sierra Pacific) 

The Small Local Exchange Carriers (Small LECs) 

Sunesys, LLC (Sunesys) 

SureWest Telephone 

Southern California Edison Company (SCE) 

Sprint Nextel (Sprint) 

The Utility Reform Network (TURN) 

T-Mobile West Corporation d/b/a/ T-Mobile (T-Mobile) 

Time Warner Cable (Time Warner) 

tw telecom of California, lp (tw telecom) 

Verizon California Inc. (Verizon) 

The workshop process resulted in many thoughtful proposals for reducing 

fire hazards. Much of the credit for the success of the workshops belongs to 

ALJ Minkin and ALJ Vieth. As a result of their leadership, the 39 parties were 

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able to debate dozens of proposals and reach a consensus in important areas. We 

also thank the workshop participants for their hard work, dedication, and many 

thoughtful proposals. 

2.3. The Phase 2 Workshop Report and Briefs 

On August 13, 2010, Sunesys filed and served the Phase 2 Joint Parties’ 

Workshop Report for Workshops Held January – June 2010 (“the Phase 2 Workshop 

Report”) on behalf of itself and the following parties: AT&T, CAISO, CalTel, 

CCTA, CFBF, CMUA, Comcast, Cox, CPSD, CTIA, Davey Tree, DRA, Frontier, 

IBEW 1245, LA County, LADWP, MGRA, NextG, Osmose, PG&E, PacifiCorp, 

SDG&E, Sierra Pacific, the Small LECs,4 SureWest, SCE, Sprint, Time Warner, 

T-Mobile, TURN, tw telecom, and Verizon. Several parties who attended the 

Phase 2 workshops did not join the Phase 2 Workshop Report. 

The Phase 2 Workshop Report presents 36 proposals that were discussed 

during the workshops. The workshop participants reached a consensus on six of 

the proposals, which are contained in Appendix A of the Workshop Report. The 

remaining proposals were contested by one or more parties. The contested 

proposals are contained in Appendix B of the Phase 2 Workshop Report. 

Opening Briefs regarding the Phase 2 Workshop Report were filed on 

September 30, 2010, by the following parties: Cal Fire, CFBF, CAISO, CMUA, a 

 

4 The Small LECs are the following carriers: Calaveras Telephone Company, Cal-Ore 

Telephone Co., Ducor Telephone Company, Foresthill Telephone Co., Happy Valley 

Telephone Company, Hornitos Telephone Company, Kerman Telephone Co., 

Pinnacles Telephone Co., The Ponderosa Telephone Co., Sierra Telephone Company, 

Inc., The Siskiyou Telephone Company, Volcano Telephone Company, and 

Winterhaven Telephone Company. 

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coalition of communication infrastructure providers (the CIP Coalition),5 CPSD, 

DRA, IBEW 1245, LA County, LADWP, Multi-Jurisdictional Utilities (MJU),6

MGRA, PG&E, SDG&E, SCE, the Small LECs, and TURN. Reply briefs were 

filed on September 17, 2010, by the following parties: CFBF, CMUA, the 

CIP Coalition, CPSD, DRA, IBEW 1245, LA County, LADWP, MGRA, 

PacifiCorp, PG&E, SDG&E, SCE, the Small LECs, Sierra Pacific,7

 and TURN. 

With the permission of the assigned ALJ, CPSD and MGRA filed a joint sur-reply 

brief on October 18, 2010, that addressed certain issues raised in PG&E’s reply 

brief. PG&E filed a response to the sur-reply brief on November 11, 2010. 

3. Commission Jurisdiction 

The purpose of this rulemaking proceeding is to consider and adopt 

regulations to reduce the fire hazards associated with (1) overhead power-line 

facilities, and (2) aerial communication facilities located in close proximity to 

overhead power lines. The California Constitution and the Public Utilities Code 

provide the Commission with broad jurisdiction to adopt regulations regarding 

 

5 The CIP Coalition is comprised of AT&T, CCTA, CTIA, Comcast, Cox, Frontier, the 

Small LECs, Sunesys, SureWest Telephone, Sprint, T-Mobile, Time Warner Cable, 

tw telecom of california, lp, and Verizon. 

6 The MJUs are PacifiCorp and Sierra Pacific. 

7 In D.10-10-017, the Commission approved the transfer of Sierra Pacific’s public 

utility facilities and operations in California to California Pacific Electric Company, 

LLC (CalPeco). Today’s decision uses “Sierra Pacific” to refer to both CalPeco and 

Sierra Pacific, unless otherwise indicated. 

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the safety of utility facilities and operations.8 Utilities are required by Pub. Util. 

Code § 702 to “obey and comply” with such requirements.9

 

The Commission has enacted an extensive set of safety regulations 

governing utility facilities and operations, including General Orders 95 and 165. 

A major goal of these General Orders is to minimize fire hazards. 

In addition to the Commission’s broad jurisdiction to regulate investorowned utilities, Pub. Util. Code §§ 8002, 8037, and 8056 provide the Commission 

with authority to adopt and enforce rules governing electric transmission and 

distribution facilities of publicly owned utilities (POUs) for the limited purpose 

of protecting the safety of employees and the general public. Today’s decision 

does not re-litigate the Commission’s determination in the OIR and the Phase 1 

Decision that it may adopt and enforce safety-related regulations for POU 

electric transmission and distribution facilities.10 

Today’s decision adopts several safety-related regulations that apply to 

electric transmission facilities. These rules do not conflict with (1) reliability 

standards issued by an Electric Reliability Organization that is certified by the 

Federal Energy Regulatory Commission (FERC), or (2) performance standards 

issued by CAISO for transmission facilities under its control pursuant to 

Pub. Util. Code § 348 or FERC-approved Transmission Control Agreements.11

 

8 Cal. Constitution, Article XII, §§ 3 and 6, and Pub. Util. Code §§ 216, 701, 761, 768, 

770, 1001, 8037 and 8056. See also San Diego Gas & Electric Company v. Superior Court, 

(1996) 13 Cal.4th 893, 923-924. 

9 See also Pub. Util. Code §§ 761, 762, 767.5, 768, 770. 

10 OIR at 6, and D.09-08-029 at 8 – 9 and Conclusion of Law 3. See also the Phase 2 

Scoping Memo at 4, Item 8. 

11 See CAISO’s comments filed June 30, 2011, regarding the proposed decision. 

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The Commission’s comprehensive jurisdiction over matters of public 

safety associated with utility facilities extends to attachments to utility poles by 

CIPs. Specifically, 47 U.S.C. § 224 provides that the Federal Communications 

Commission (FCC) does not have “jurisdiction [under 47 U.S.C. § 224] with 

respect to rates, terms, and conditions, or access to poles, ducts, conduits, and 

rights-of-way as provided in subsection (f) for pole attachments in any case 

where such matters are regulated by a State.” The Commission has certified to 

the FCC that the Commission regulates the rates, terms, and conditions of access 

to poles, conduits, ducts, and rights-of-way in conformance with 47 U.S.C. 

§§ 224(c)(2) and (3).12 Further, under 47 U.S.C. § 253(b) the Commission may 

adopt regulations to protect public safety and welfare. 

Likewise, the Cable Communications Policy Act of 1984 specifically grants 

states jurisdiction over cable service in safety matters. (47 U.S.C. § 556 (a).) The 

California Legislature asserted such jurisdiction in Pub. Util. Code § 768.5, which 

gave the Commission authority to regulate cable companies with respect to the 

safe operation, maintenance, and construction of their facilities. 

4. Criteria for the Adoption of New Regulations 

The main purpose of this proceeding is to consider and adopt regulations 

to reduce the fire hazards associated with overhead power-lines and aerial 

communication facilities in close proximity to power lines. Therefore, in 

deciding whether to adopt the proposals in the Phase 2 Workshop Report, the 

primary standard we will use is whether the proposals are likely to reduce fire 

hazards. We must also consider the costs of the proposed regulations. If the cost 

 

12 D.98-10-058, 82 CPUC2d 510, 531, as modified by D.00-04-061, 6 CPUC3d 1, 5. 

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of a proposed regulation appears to exceed the benefits to be gained from the 

reduction in fire hazards, the regulation should be rejected. 

Because this is a quasi-legislative rulemaking proceeding,13 today’s 

decision may rely on legislative facts14 obtained from written submissions in this 

proceeding, such as the Phase 2 Workshop Report and briefs. We may also draw 

on evidence from past proceedings, our experience and expertise in regulating 

utilities, our current policies, and common sense.15 

We do not need to rely on formal evidence or hold an evidentiary hearing 

in a quasi-legislative rulemaking proceeding. As set forth in Pub. Util. Code 

§ 1708.5(f), “the commission may conduct any proceeding to adopt, amend, or 

repeal a regulation using notice and comment rulemaking procedures, without 

an evidentiary hearing, except with respect to a regulation being amended or 

repealed that was adopted after an evidentiary hearing, in which case the parties 

to the original proceeding shall retain any right to an evidentiary hearing 

accorded by Section 1708.” Notice of OIR 08-11-005 was served on all potential 

parties, including regulated electric corporations, municipal electric utilities, and 

CIPs operating in California.16 Parties were given an opportunity to request an 

 

13 Phase 1 Scoping Memo at 16. A quasi-legislative proceeding establishes policies or 

rules affecting a class of regulated utilities. (Rule 1.3(d) of the Commission’s Rules of 

Practice and Procedure.) 

14 Legislative facts are general facts that help the Commission to decide questions of 

law and policy and discretion. (Rule 13.3(c) of the Commission’s Rules of Practice 

and Procedure.) 

15 D.06-06-071 at 26; D.06-12-029 at 13 – 14; D.04-03-041 at 11; and D.99-07-047, 

1 CPUC3d 627, 634 – 636. 

16 OIR 08-11-005, at Ordering Paragraph 6. 

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evidentiary hearing using the procedures in the Phase 1 and Phase 2 Scoping 

Memos. No party requested an evidentiary hearing17 and none was held. 

5. Consensus Proposals 

Appendix A of the Phase 2 Workshop Report contains six consensus 

proposals to revise the Commission’s General Orders. There is no opposition to 

the consensus proposals. We address each of the consensus proposals below. 

5.1. Consensus Proposal 1 re: GO 95, Rule 18A 

5.1.1. Summary of Proposal 

Rule 18A of General Order (GO) 95 requires CIPs and electric utilities to 

correct safety hazards and violations of GO 95. Consensus Proposal 1 would 

replace the word “violation” in Rule 18A with the word “nonconformance.” The 

proposed revisions to Rule 18A are shown in Appendix A of today’s decision.18 

The parties do not expect Consensus Proposal 1 to have any financial 

impact on electric utilities or CIPs. 

5.1.2. Position of the Parties 

Most parties either did not address Consensus Proposal 1 in their briefs or 

expressed general support for the proposal. 

CPSD does not believe the consensus proposal to replace the word 

“violation” with “nonconformance” will improve safety. CPSD is neutral on the 

 

17 Certain parties initially requested an evidentiary hearing in Phase 1, but later opted 

for workshops in lieu of evidentiary hearings. (D.09-08-029 at 6.) 

18 The consensus proposal to revise Rule 18A is in addition to two contested proposals 

to revise Rule 18A that are addressed later in today’s decision. 

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proposal because, in CPSD’s opinion, it does not matter which word is used, as 

the Commission has determined that a “nonconformance” is a “violation.”19 

SCE believes there is an important distinction between the words 

“nonconformance” and “violation.” SCE states that the term nonconformance is 

broader than violation. By using the term nonconformance, the applicability of 

Rule 18A will be broadened to encompass conditions that do not rise to a level 

that is considered to be a violation by Commission decisions. 

5.1.3. Discussion 

We agree with the Phase 2 Workshop Report that revising Rule 18A to use 

the word “nonconformance” in place of “violation” will facilitate the timely 

correction of all conditions that do not adhere to the requirements of GO 95.20 

The timely correction of non-conforming conditions should help achieve our goal 

of improved fire safety. The consensus revisions to Rule 18A are also consistent 

with the terminology found in GO 95, Rule 12.6 (Third Party Nonconformance) 

and Rule 35 (Vegetation Management) – Exception #3. 

For the preceding reasons, we find the consensus revisions to Rule 18A are 

reasonable in light of the record, consistent with the law, and in the public 

interest. We therefore adopt the revisions. The text of the revised Rule 18A is 

contained in Appendix B of today’s decision.21

 

19 D.04-04-065, 2004 Cal. PUC LEXIS 207 at *18. 

20 Phase 2 Workshop Report, Appendix A, at A-8. 

21 The revised Rule 18A adopted by today’s decision reflects the consensus revisions as 

well as certain contested revisions that are addressed later in today’s decision. 

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5.2. Consensus Proposal 2 re: GO 95, Rule 18B 

5.2.1. Summary of Proposal 

Rule 18B of GO 95 requires that if one company discovers a safety hazard 

with respect to another company’s facilities, the first company must notify the 

second company of the hazard no later than 10 business days after the discovery. 

Consensus Proposal 2 consists of several proposed revisions to Rule 18B that are 

intended to clarify the rule. The proposed revisions to Rule 18B are shown in 

Appendix A of today’s decision. 

A first consensus revision concerns the applicability of Rule 18B. The rule 

currently applies when a company is “inspecting its facilities.” The consensus 

revision replaces the phrase “inspecting its facilities” with “performing 

inspections.” The replacement phrase is intended to clarify that Rule 18B applies 

to inspections during the normal course of business, and not to emergency 

situations when companies must inspect their facilities to remedy the emergency. 

The second consensus revision adds flexibility to the notification 

requirement. Rule 18B currently requires that notifications be “in writing.” The 

revision requires that notifications be “documented” to avoid limiting the 

methods used by a company to notify another company of a safety hazard. For 

example, the proposed revision would allow the inspecting company to meet the 

notification requirement by making a phone call and then documenting the call. 

The third consensus revision provides greater flexibility for a pole owner 

that is informed about a safety hazard with the facilities of one of its pole tenants. 

Currently, the pole owner must notify the pole tenant of the safety hazard 

“promptly.” The proposed revision states that the timeframe is “normally” not 

to exceed five business days. The use of the word “normally” reflects the fact 

that it is sometimes impossible to provide notice within five business days. This 

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could occur, for example, when the pole owner must visit facilities that are 

located on land where the property owner refuses to provide access. 

The fourth consensus revision to Rule 18B simplifies the term “electric 

transmission or distribution facility” to “electric facility.” 

The fifth revision removes the requirement that the inspecting company 

must state in its notification whether the safety hazard is in a high fire-threat 

zone. The workshop participants agreed that this requirement is unnecessary. 

The final consensus revision is to the sentence that states: “It is the 

responsibility of each pole owner to know the identity of each entity using or 

maintaining equipment on its pole.” Several parties expressed concern about 

whether Rule 18B requires each joint owner of a utility pole to know the identity 

of every entity that another joint owner leases its space to. The consensus 

revision clarifies this requirement by stating that a company must be able to 

determine the identity of (1) its own pole tenants, and (2) other pole owners. 

The authors of the Phase 2 Workshop Report do not expect the consensus 

revisions to Rule 18B to increase costs significantly. 

5.2.2. Position of the Parties 

Most parties either did not address Consensus Proposal 2 in their briefs or 

expressed general support for the proposal. 

SCE submits that the consensus revisions to Rule 18B will make it clear 

that utility inspectors do not need to apply the rule’s requirements during 

emergencies or trouble calls when the focus is on restoring service. 

SCE states that the consensus revisions also recognize the difficulties faced 

by joint owners of utility poles in identifying every pole tenant. While a utility 

knows the tenants in the space it owns on jointly owned poles, the utility does 

not always know the tenants in the space of the other pole owners. The revised 

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rule recognizes this reality, and permits the inspecting company to notify the 

relevant joint owner when it cannot identify the tenant whose facilities are 

causing a safety hazard. It is then the responsibility of the relevant joint owner 

to notify its tenant of the hazard. 

In its opening brief, SCE proposed – apparently for the first time – to revise 

Rule 18B to remove all deadlines for providing notice of safety hazards. SCE 

disfavors placing time frames and other operational requirements in GO 95. 

Instead, SCE favors a “programmatic approach” to regulation within GO 95. 

Specifically, GO 95 should contain the standards to be met by regulated utilities. 

The utilities should be required to develop a program to meet those standards, 

and Commission staff should audit the utilities to ensure their programs are 

designed to meet the standards and that each utility is following its program. 

This approach allows each utility to consider the unique aspects of its service 

territory and operations when developing compliance programs. 

5.2.3. Discussion 

We agree with the rationale in the Phase 2 Workshop Report that the 

consensus revisions to Rule 18B will clarify and streamline the requirements 

regarding the notification of safety hazards.22 This will facilitate notice of safety 

hazards to the entities responsible for correcting the hazards which, in turn, 

should help to reduce safety hazards over time. 

For the preceding reasons, we find the proposed consensus revisions to 

Rule 18B are reasonable in light of the record, consistent with the law, and in the 

 

22 Workshop Report, Appendix A, at A-12 to A-14. 

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public interest. We therefore adopt the revisions. The text of the revised 

Rule 18B is contained in Appendix B of today’s decision. 

We decline to adopt SCE’s proposal to eliminate from Rule 18B the 

deadlines for providing notice of safety hazards. We believe SCE’s proposal 

would be detrimental to public safety, as it would eliminate the requirement for 

a utility to provide notice of an observed safety hazard to the entity responsible 

for correcting the hazard within a specified timeframe. It is not in the public 

interest to adopt a proposal that would allow an observed safety hazard to go 

unreported (and uncorrected) indefinitely. 

5.3. Consensus Proposal 3 re: GO 95, Rule 35 

5.3.1. Summary of Proposal 

Rule 35 of GO 95 requires electric utilities and CIPs to keep their overhead 

facilities clear of vegetation. Consensus Proposal 3 consists of revisions to 

Paragraphs 1 – 3 of Rule 35. The consensus revisions to Rule 35 are shown in 

Appendix A of today’s decision. 

The consensus revisions to Paragraph 1 clarify that Rule 35 applies to all 

electric utility and CIP facilities located on lands owned by state and local 

agencies. This is intended to ensure consistent vegetation management practices 

on all lands throughout the state.23 

The consensus revisions to Paragraph 2 clarify that it is permissible for 

healthy trees to lean toward or overhang conductors, and that electric utilities 

and CIPs should trim or remove a tree only when they have actual knowledge 

 

23 Nothing in the proposed revisions to Rules 35 is meant to suggest that the minimum 

clearances currently in Table 1, Cases 13 and 14 apply to communication lines. 

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that a dead, rotten or diseased tree (including trunks, limbs, or branches) is 

poised to fall onto a power line or communication line. Also, the term “span” is 

modified to include the phrase “of supply or communication lines” to avoid 

interpretive errors.24

The consensus revisions to Paragraph 3 clarify that low voltage conductors 

(0 – 750 volts) deflected by trees, but still within allowable tension, are subject to 

vegetation management in order to avert support structure damage or failure 

due to excessive transverse loads. 

The Phase 2 Workshop Report states that it is unknown at this time 

whether Consensus Proposal 3 will result in additional costs. 

5.3.2. Position of the Parties 

Most parties either did not address Consensus Proposal 3 in their briefs or 

expressed general support for the proposal. 

CPSD, PG&E, and SCE aver that the consensus revisions to Rule 35 will 

clarify that vegetation management requirements apply to facilities located on 

state and local lands, which should help utilities to deal with government entities 

that refuse to allow utilities to perform vegetation management work. PG&E 

and SCE add that the consensus revisions will also clarify that (1) it is 

permissible for healthy trees or limbs to overhang or lean toward conductors; 

and (2) vegetation-related strain on a conductor needs to be corrected when it 

compromises the integrity of the supporting structures. 

 

24 Today’s decision uses the terms “power line” and “supply line” interchangeably. 

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5.3.3. Discussion 

We find that the consensus revisions to Rule 35 will enhance public safety 

by reducing the fire hazards associated with overhead electric utility and CIP 

facilities. In particular, the consensus revisions to Paragraph 1 of Rule 35 will 

require overhead power lines and communication lines located on lands owned 

by state and local public agencies to be kept clear of vegetation. 

The consensus revisions to Paragraph 2 will help electric utilities and CIPs 

to determine when a tree that overhangs or leans toward a conductor should be 

trimmed or removed. This should make vegetation management activities more 

efficient and effective at reducing fire hazards. 

Finally, the consensus revisions to Paragraph 3 will clarify that electric 

utilities and CIPs are responsible for remedying vegetation-related strain on 

conductors energized at 750 volts or less. This should reduce the incidence of 

damaged lines, appurtenances, and support structures, and thereby reduce 

safety risks to workers and the general public. 

Although the Phase 2 Workshop Report does not provide an estimate of 

the costs, if any, to implement the consensus revisions to Rule 35, we anticipate 

such costs will be minimal. 

For the preceding reasons, we find the proposed consensus revisions to 

Rule 35 to be reasonable in light of the record, consistent with the law, and in the 

public interest. We therefore adopt the revisions. The text of the revised Rule 35 

is contained in Appendix B of today’s decision. The adopted text includes the 

correction of the following typo, omission, and inconsistency in the Phase 2 

Workshop Report: (1) replacing the period at the end of the first sentence of 

Rule 35, Paragraph 1, with a comma, so that the first and second sentences are 

combined into one sentence; (2) adding the word “General” before “Order” in 

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the last sentence of the first paragraph; and (3) replacing the word “violation” 

with “nonconformance” in the last sentence of the third paragraph, which is 

consistent with the use of the word “nonconformance” in the Third Exception 

listed in Rule 35 and in the adopted consensus revisions to Rule 18A. 

5.4. Consensus Proposal 4 re: GO 95, Rule 37, Table 1, 

Case 14 and Footnotes (fff) - (jjj) 

5.4.1. Summary of Proposal 

The Phase 1 Decision modified Rule 37, Table 1, Case 14, and associated 

Footnotes (fff) through (jjj). These modifications (1) expanded the minimum 

vegetation clearances around bare-line conductors in the high fire-threat areas of 

Southern California, and (2) required the expanded minimum clearances to be 

maintained on a year-round basis, not just during fire season.25 The Phase 1 

Decision also excluded orchards from the expanded clearances, recognizing that 

actively managed orchards pose less of a fire hazard than other areas. These 

measures were adopted on an interim basis pending further review in Phase 2. 

However, there were no proposals to revise the interim measures in Phase 2. 

The purpose of Consensus Proposal 4 is to permanently adopt the 

“interim” revisions to Rule 37 and to correct typographical errors in 

Footnote (fff). The proposed revisions are shown in Appendix A of today’s 

decision. The parties do not anticipate that the conversion of the interim rule 

into a permanent rule will result in significant additional costs, although the rule 

itself - whether interim or permanent - does impose costs. 

 

25 D.09-08-029 at 31 – 32. 

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5.4.2. Position of the Parties 

Most parties either did not address Consensus Proposal 4 in their briefs or 

expressed general support for the proposal. 

SCE observes that Footnote (hhh) of Rule 37 contains a reference to 

Cal Fire’s Fire and Resource Assessment Program (FRAP) Fire Threat Map. SCE 

notes that one of the issues before the Commission in Phase 2 of this proceeding 

is the selection of appropriate fire-threat maps. SCE requests that the 

Commission affirm that the use of Cal Fire’s FRAP Map as referenced in 

Footnote (hhh) and elsewhere in GO 95 and GO 165 is subject to change. 

5.4.3. Discussion 

We conclude that the permanent adoption of expanded vegetation 

clearances around bare-line conductors in the high fire-threat areas of Southern 

California will promote our goal of reducing fire risks. We also find that it is 

reasonable to exclude actively managed orchards from the expanded vegetation 

clearances because, as was noted in the Phase 1 Decision, such orchards pose less 

of a fire hazard.26 Although there will be costs to comply with the expanded 

vegetation clearances, no party objects to the costs. We find that such costs are 

outweighed by the public-safety benefits. 

For the preceding reasons, we find the consensus revisions to Rule 37 are 

reasonable in light of the record, consistent with the law, and in the public 

interest. We therefore adopt the revisions. The text of the revised Rule 37, 

Table 1, Case 14 and Footnotes (fff) – (jjj) is in Appendix B of today’s decision. 

 

26 D.09-08-029 at 31-32. As noted in Rule 37, Table 1, Case 14, Footnote (jjj), the Case 13 

clearances apply to plowed or cultivated orchards of fruit, nut, or citrus trees. 

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In response to SCE’s request that we affirm that the use of the FRAP Map 

as referenced in Footnote (hhh) of Rule 37 and elsewhere in GO 95 and GO 165 

may be changed in the future, we note that later in today’s decision we establish 

a Phase 3 of this proceeding for the specific purpose of developing and adopting 

fire-threat maps to replace the FRAP Map. 

5.5. Consensus Proposal 5 re: GO 95, Rules 23.0, 44.1, 

44.2, and 44.3

5.5.1. Summary of Proposal 

Consensus Proposal 5 consists of revisions to Rules 23.0, 44.1, 44.2, and 

44.3 of GO 95. The proposed revisions are shown in Appendix A of today’s 

decision. 

 The consensus revisions to Rule 23.0 have the effect of applying the safety 

factors for new construction in Rule 44.1 to a “change to an existing grade of 

construction or class of circuit.” 

The consensus revisions to Rule 44.1 add “mechanical strength” as a 

design criterion for lines and elements of lines that are installed or reconstructed. 

This will help ensure that mechanical strength is both considered during design 

calculations and subject to the safety factors in Rule 44.1. The proposed revisions 

to Rule 44.1 also replace the word “utility” with “company” to reflect that the 

entity doing the installation or reconstruction may not be a utility. 

There are several consensus revisions to Rule 44.2. The first revision 

clarifies that Rule 44.2 applies to any “supply or communication company,” 

rather than to any “utility.” The second revision changes “utility” to “company” 

in several spots to clarify that Rule 44.2 applies to companies that may not 

technically be utilities. The third revision clarifies that a load calculation is 

required before a company adds facilities that materially increase vertical, 

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transverse, and longitudinal loads. This is intended to promote public safety by 

ensuring that all loads are considered before facilities are added. The fourth 

revision changes a general reference to “Section IV” to a specific reference to 

“Rule 44.3.” This clarifies which design criteria are applicable to additional 

construction on poles. The fifth revision requires the company doing load 

calculations to maintain records of its calculations for five years. This is 

consistent with the five-year document-retention requirement in Rule 19. The 

sixth revision changes “intrusive pole loading data” to the more accurate 

“intrusive pole test results.” The final revision eliminates a note added by 

D.09-08-029 that states, “Nothing contained in this rule shall be construed as 

allowing the safety factor of a facility to be reduced below the required values 

specified in Rules 44.1 and 44.3.” The workshop participants agreed that this 

note is no longer necessary given the consensus revisions to Rule 44.3 addressed 

below and the specific reference to Rule 44.3 that is being added to Rule 44.2. 

Rule 44.3 requires replacement or reinforcement of lines or parts thereof 

before safety factors fall below specified levels due to deterioration. The 

consensus revision adds “installation of additional facilities” as another factor 

that would justify replacement or reinforcement. The new text is a more direct 

way of stating the concept already embodied in the note to Rule 44.2 and thereby 

allows for the elimination of the note. 

The Phase 2 Workshop Report states that the cost impacts of the proposed 

revisions are not certain. Companies that currently do not retain pole loading 

calculations for five years may incur additional document retention costs. The 

inclusion of additional design criteria could lead to more pole replacements 

and/or reinforcements, and thus higher costs. 

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5.5.2. Position of the Parties 

Most parties either did not address Consensus Proposal 5 in their briefs or 

expressed general support for the proposal. 

CPSD, PG&E, and SCE support Consensus Proposal 5 because it will help 

ensure that (1) companies perform pole-loading calculations, and (2) poleloading calculations employ the correct safety factors and consider both 

structural loads and mechanical strength. 

5.5.3. Discussion 

With one exception, we agree with the Phase 2 Workshop Report that the 

consensus revisions to Rules 23.0, 44.1, 44.2 and 44.3 will clarify which design 

criteria are applicable to the installation, reconstruction, addition, and 

replacement of facilities on utility poles.27 This should promote public safety by 

helping to ensure that utility poles and attachments do not fail and thereby ignite 

a fire. The revisions also clarify that Rule 44.2 applies to any “company” 

planning to add facilities to a pole, rather than to any “utility.” This change 

should promote public safety by helping to ensure that both electric and 

telecommunications companies are expected to perform and share pole-loading 

calculations. Although the exact costs of these consensus revisions are unknown, 

no party objects to these costs. We find that such costs are unlikely to exceed the 

public-safety benefits of the adopted revisions. 

The one exception concerns the proposed five-year record retention period 

for pole-loading calculations. We believe that a longer record retention period is 

needed so that we may conduct a thorough forensic analysis in the event there is 

 

27 Workshop Report, Appendix A, page A-31. 

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a major safety-related incident. To this end, we will require CIPs and electric 

utilities to henceforth retain records of pole-loading calculations for ten years. 

This new record-retention requirement applies to records currently in an entity’s 

possession and records created on or after the date of today’s decision. 

For the preceding reasons, we find the proposed revisions to GO 95, 

Rules 23, 44.1, 44.2, and 44.3, as revised by today’s decision, are reasonable in 

light of the record, consistent with the law, and in the public interest. We 

therefore adopt the revisions. The text of revised rules is contained in 

Appendix B of today’s decision.28

5.6. Consensus Proposal 6 re: GO 165, Sections I - IV 

5.6.1. Summary of Proposal 

Consensus Proposal 6 consists of several revisions to GO 165. The 

proposed revisions to GO 165 are shown in Appendix A of today’s decision. 

The first consensus revision extends the inspection and reporting 

requirements in GO 165 to all outdoors electric distribution and transmission 

facilities (except substations)29 that are under the Commission’s jurisdiction, 

including facilities that belong to non-electric utilities such as Southern 

California Gas Company, which owns an overhead electric distribution system at 

 

28 The revised Rule 44.2 adopted by today’s decision reflects the consensus revisions as 

well as certain contested revisions that are addressed later in today’s decision. The 

revised Rule 44.3 is corrected to add the word “rule” to the last sentence so that it 

reads: “In no case shall the application of this rule....” 

29 The proposed consensus revisions do not apply to substations because the 

Commission is currently considering a new general order in R.10-09-001 that would 

contain inspections and reporting requirements for electric substation facilities. 

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its Aliso Canyon storage field. Consensus Proposal 6 specifically excludes CIP 

facilities and cathodic protection systems for natural gas facilities from GO 165. 

The second consensus revision streamlines the recordkeeping and 

reporting requirements in GO 165. 

The final consensus revision adds a new Section III.E to GO 165 that 

creates a mechanism to revise GO 165 that is similar to the mechanism in 

Rule 15.1 of GO 95. The proposed Section III.E would allow entities to request 

revisions to maintenance and inspection programs based on new technology and 

practices without a formal Commission proceeding. 

The Phase 2 Workshop Report acknowledges that CAISO has oversight 

responsibilities for the electric transmission facilities under its operational 

authority. CAISO requires Participating Transmission Owners to inspect and 

maintain their transmission facilities according to pre-approved plans, and to 

submit reports to CAISO on their inspection and maintenance activities. The 

Phase 2 Workshop Report states that the consensus revisions that pertain to the 

inspection and maintenance of electric transmission facilities do not conflict with 

CAISO regulations. 

The Phase 2 Workshop Report notes that the consensus revisions will not 

increase costs for electric utilities that are currently covered by GO 165. On the 

other hand, companies that are newly subject to GO 165, including non-electric 

utilities such as SoCalGas, will incur additional costs to comply with GO 165. 

5.6.2. Position of the Parties 

Most parties either did not address Consensus Proposal 6 in their briefs or 

expressed general support for the proposal. 

CAISO agrees that the consensus revisions to GO 165 do not conflict with 

its jurisdiction and regulations. CPSD avers that Consensus Proposal 6 will 

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enable CPSD to ensure that transmission facilities in California are adequately 

inspected and maintained, without duplicating CAISO’s regulations. PG&E and 

SCE submit that the consensus revisions will vastly improve GO 165 by 

streamlining many of its requirements. 

5.6.3. Discussion 

With one exception described below, we agree with the assessment in the 

Phase 2 Workshop Report that the consensus revisions will streamline and 

clarify GO 165, thereby making it more useful to utilities and CPSD.30 These 

revisions should improve compliance and reduce costs. Extending GO 165 to 

additional electric distribution and transmission facilities located outside of 

buildings should promote public safety and reduce fire hazards by ensuring that 

these additional facilities are inspected in accordance with GO 165. As noted by 

CAISO, the proposed revisions to GO 165 do not conflict with CAISO’s 

jurisdiction or regulations. 

Our one reservation with the consensus revisions to GO 165 is the 

following provision that would add a new mechanism for seeking future 

exemptions from, or modifications to, GO 165: 

If, in a particular case, exemption from or modification of any 

of the requirements herein is desired, the Commission will 

consider a request for such exemption or modification when 

accompanied by a full statement of conditions existing and the 

reasons why such exemption or modification is asked and is 

believed to be justifiable. It is to be understood that, unless 

otherwise ordered, any exemption or modification so granted 

shall be limited to the particular case covered by the request. 

 

30 Phase 2 Workshop Report, Appendix A, page A-50. 

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The above provision is vague because it does not (1) state who may ask for 

an exemption or modification, or (2) specify a procedure for seeking an 

exemption or modification. The provision is also unnecessary because the 

Commission already has procedures to request an exemption or modification, 

including applications, petitions for modification of Commission decisions, and 

petitions for new rulemaking proceedings. We therefore see no value or need for 

the above provision, and we decline to adopt it. 

For the preceding reasons, we find that the proposed consensus revisions 

to GO 165, as modified by today’s decision, are reasonable in light of the record, 

consistent with the law, and in the public interest. We therefore adopt the 

revisions. The text of the revised GO 165 in contained in Appendix B of today’s 

decision.31 We recognize that the adopted revisions to GO 165 could increase 

costs for companies that were not previously subject to GO 165. However, no 

party suggests that such costs are unreasonable. We find that the increased costs 

are unlikely to exceed the public-safety benefits of the adopted revisions. 

6. Contested Proposals 

The Phase 2 Workshop Report contains more than two dozen contested 

proposals for improving fire safety. These proposals are presented in 

Appendix B of the Workshop Report. We address the contested proposals 

below. 

 

31 The adopted text corrects two typos. The first correction is in Section III.B where the 

word “assure” is replaced with “ensure.” The second correction is in Note 1 under 

the Sample Report Template where “their” is replaced with “its.” 

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6.1. Contested Proposals 1A and 1B re: GO 95, Rule 11 

6.1.1. Summary of Proposals 

Rule 11 of GO 95 contains a short description of the purpose of GO 95. The 

Phase 2 Workshop Report presents two competing proposals by CPSD and the 

CIP Coalition to revise Rule 11. The proposed revisions are shown below with 

strikeout and underline: 

CPSD Contested Proposal 1A

The purpose of these rules is to formulate, for the State of 

California, uniform requirements for overhead electrical line 

design, construction, and maintenance, the application of 

which will einsure adequate service and secure safety to 

persons engaged in the construction, maintenance, operation 

or use of overhead electrical lines and to the public in general. 

CIP Coalition Contested Proposal 1B

The purpose of these rules is to formulate, for the State of 

California, uniform requirements for overhead electrical line 

design, construction, and maintenance, the application of 

which will einsure adequate service and secure safety to 

persons engaged in the construction, maintenance, operation 

or use of overhead electrical lines and to the public in general. 

The only difference between the two competing proposals is that CPSD 

would remove the modifier “electrical” before the word “line,” while the 

CIP Coalition would retain the modifier “electrical.” 

6.1.2. Position of the Parties 

CPSD states that its proposed revisions to Rule 11 (Contested Proposal 1A) 

will clarify that GO 95 applies to communication lines in addition to electrical 

lines. CPSD notes that when Rule 11 was adopted in 1922, both power lines and 

communication lines conducted electricity. Thus, historically, the term 

“electrical lines” as used in Rule 11 included “communication lines.” Removing 

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the modifier “electrical” should prevent GO 95 from being misinterpreted as 

applying only to electrical lines. 

CPSD states that its proposal will also clarify that GO 95 specifies design 

and maintenance standards in addition to construction standards. CPSD asserts 

that this clarification is necessary because some companies have told CPSD that 

Rule 11 only requires that lines be constructed in accordance with GO 95, and 

not designed and maintained in accordance with the GO 95. 

CPSD’s proposal is supported by DRA, IBEW 1245, PacifiCorp, PG&E, 

SCE, SDG&E, and Sierra Pacific. Although PG&E and SCE support CPSD’s 

proposal, they are concerned that both CPSD’s and the CIP Coalition’s proposals 

would broaden the focus of GO 95 to include design and maintenance. 

Traditionally, the utilities have had flexibility to tailor their internal operations to 

fit their individual needs. Adding more detail to GO 95 will reduce flexibility. 

SDG&E agrees that CPSD’s proposal to eliminate the modifier “electrical” 

from Rule 11 should remove confusion over what types of lines GO 95 applies to. 

Unlike PG&E and SCE, SDG&E is not concerned about the addition of the words 

“design” and “maintenance” to Rule 11, since certain rules in GO 95 already 

address the design and maintenance of overhead power lines and 

communication lines. SDG&E also supports the elimination of the word 

“uniform” from Rule 11 to acknowledge the fact that the requirements for 

overhead power lines and communication lines are not uniform. 

SDG&E disagrees with the CIP Coalition’s position, summarized below, 

that CPSD has not justified deletion of “electrical” or explained how this deletion 

would impact the other 400+ pages of GO 95. SDG&E opines that CPSD’s 

proposal appropriately precludes the possibility of CIPs arguing that GO 95 does 

not apply to communications lines because the “purpose” section of Rule 11 only 

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mentions “electrical” lines. SDG&E further states that the other provisions of 

GO 95 stand on their own and are not affected by CPSD’s proposed deletion of 

the word “electrical” from the “purpose” section of GO 95. 

The CIP Coalition urges the Commission to adopt the CIP Coalition’s 

proposal (Contested Proposal 1B) and reject CPSD’s proposal. The CIP Coalition 

argues that CPSD has not explained how the deletion of the word “electrical” in 

Rule 11 would impact the 400+ pages of GO 95. Because Rule 11 has not been 

modified since its adoption in 1922, the removal of the word “electrical,” without 

reviewing the entirety of GO 95 and making any necessary conforming changes, 

adds an element of uncertainty to GO 95. The CIP Coalition adds that removing 

the word “electrical” does not advance the objective of this proceeding of 

reducing the fire hazards associated with utility facilities. 

6.1.3. Discussion 

We conclude for the following reasons that CPSD’s proposed revisions to 

Rule 11 are reasonable, and we adopt them. There is no additional cost for the 

adopted revisions to Rule 11, as they only clarify existing requirements. The text 

of the revised Rule 11 is contained in Appendix B of today’s decision. 

CPSD’s and the CIP Coalition’s competing proposals to revise Rule 11 are 

identical in most respects. Both proposals add the words “design” and 

“maintenance” to the described purpose of GO 95, since GO 95 specifies design 

and maintenance standards for overhead lines. Both proposals also eliminate the 

modifier “uniform” before the word “requirements” to reflect the fact that GO 95 

has different requirements for overhead power lines versus communication lines 

in some instances. These technical revisions to Rule 11 are clearly reasonable. 

The only difference between the two proposals is that CPSD’s proposal 

would delete the modifier “electrical” prior to the word “line” in two places, so 

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that Rule 11 would state the purpose of GO 95 is to formulate requirements for 

“overhead line design, construction, and maintenance” rather than “overhead 

electrical line design, construction, and maintenance.” The CIP Coalition would 

retain the modifier “electrical.” 

We find that CPSD’s proposal provides a more accurate description of the 

purpose of Rule 11. GO 95 applies to both overhead power lines and overhead 

communication lines. Removing the modifier “electrical,” as CPSD proposes, 

should eliminate the possibility that Rule 11 could be misinterpreted to mean 

that GO 95 applies only to electric power lines, and not to communication lines. 

The CIP Coalition’s fear that removing the word “electrical” may have 

unintended impacts on the other 400+ pages of GO 95 is unfounded. The 

CIP Coalition did not cite one example of unintended consequences; nor did we 

find any unintended consequences in our own review of GO 95. To the contrary, 

we find that removing the modifier “electrical” from Rule 11 has the salutary 

effect of harmonizing the rule with the remainder of GO 95. 

We disagree with the CIP Coalition’s position that deleting the modifier 

“electrical” from Rule 11 does nothing to enhance public safety. As stated 

previously, deleting the modifier “electrical” removes the possibility that Rule 11 

could be misinterpreted to mean that GO 95 does not apply to communication 

lines. This will help ensure that CIPs comply with the many safety-related rules 

in GO 95, which should improve the overall fire safety of overhead facilities. 

6.2. Contested Proposal 2 re: GO 95, Rule 12 and GO 165 

6.2.1. Summary of Proposal 

Rule 12 of GO 95 specifies which facilities are subject to GO 95. CPSD 

proposes to add a provision to Rule 12 that states GO 95 applies to 

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publicly owned utilities (POUs). CPSD also proposes similar revisions to 

GO 165. The proposed revisions are shown in Appendix A of today’s decision. 

6.2.2. Position of the Parties 

CPSD represents that it routinely meets resistance from POUs when 

enforcing the Commission’s safety rules that pertain to electric facilities. CPSD 

asserts that GO 95 and GO 165 should state that POUs are subject to these 

General Orders in order to facilitate CPSD’s ability to conduct safety audits and 

enforce the Commission’s safety rules. 

CPSD’s proposal is supported by DRA and IBEW 1245. However, 

IBEW 1245 believes it would be problematic for the Commission to impose fines 

or directives on POUs that have a material impact on their finances. 

CMUA and LADWP oppose CPSD’s proposal. They note that CPSD 

submitted the same proposal in Phase 1, which was rejected by the Phase 1 

Decision. CMUA and LADWP argue that CPSD should not be allowed to raise 

the same issue again. 

CMUA contends that CPSD has failed to justify its proposal. As far as 

CMUA is aware, the POUs in California cooperate with CPSD despite 

jurisdictional disputes. This is because POUs value the input provided by CPSD 

and treat GO 95 and GO 165 as industry standards. 

6.2.3. Discussion 

As in Phase 1, CPSD proposes to revise GO 95 and GO 165 to state that 

these General Orders apply to POUs. The Phase 1 Decision rejected the proposal 

for the following reasons: 

CPSD also recommended that we adopt language expressly 

stating that General Order 95 applies to municipal electric 

utilities. CPSD makes this recommendation in response to 

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owned utilities when seeking to enforce the Commission’s 

rules and regulations concerning the safety of overhead and 

underground electric transmission and distribution facilities. 

In response to CPSD’s concerns, we urge greater cooperation 

with CPSD. We agree with SCE that Rule 12 is sufficient to 

bind all entities that fall within the Commission’s jurisdiction 

and again restate that under Pub. Util. Code §§ 8002, 8037, 

and 8056, the Commission’s jurisdiction extends to publiclyowned utilities for the limited purpose of adopting and 

enforcing rules governing electric transmission and 

distribution facilities to protect the safety of employees and 

the general public. (D.09-08-029 at 16.) 

We decline to revisit our decision in Phase 1 where we rejected CPSD’s 

proposed revisions to Rule 12 of GO 95. If parties were allowed to resubmit their 

rejected Phase 1 proposals in Phase 2, then Phase 1 would have served no 

purpose. Although we do not adopt CPSD’s proposed revisions to Rule 12 of 

GO 95 (and similar revisions to GO 165), we are troubled that CPSD reports it 

encounters resistance from POUs when inspecting and auditing POU facilities 

subject to the Commission’s jurisdiction. We remind the POUs of our 

determination in D.09-08-029 that the Commission has authority under Pub. Util. 

Code §§ 8002, 8037, and 8056 to adopt and enforce rules governing electric 

transmission and distribution facilities to protect the safety of employees and the 

general public. If a POU refuses to cooperate with an inspection or audit of its 

facilities by CPSD, or refuses to correct a safety-related violation, then CPSD 

should bring this matter to our attention so that we may take appropriate action. 

6.3. Contested Proposals 3A and 3B re: GO 95, Rule 18A 

6.3.1. Summary of Proposals 

Rule 18A of GO 95 requires all CIPs and electric utilities subject to the 

Commission’s jurisdiction to (1) establish auditable maintenance programs for 

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their overhead facilities; (2) categorize nonconformances in accordance the three 

priority levels specified in Rule 18A; (3) correct nonconformances within the time 

frame specified for each priority level; and (4) maintain auditable records of their 

maintenance programs and corrective actions. Rule 18A also directs electric 

utilities that have auditable maintenance programs under GO 165 that are 

consistent with Rule 18A to continue to follow their GO 165 programs. 

The CIP Coalition32 and SDG&E present similar proposals to revise 

Rule 18A.33 Both proposals remove what the CIP Coalition and SDG&E see as 

conflicting, unnecessary, and redundant provisions. For example, both 

proposals delete Item 4 of Rule 18A, which requires companies to correct within 

30 days the following: (1) certain nonconformances located in Extreme and Very 

High Fire Threat Zones in Southern California, and (2) a significant safety risk to 

utility employees. The CIP Coalition and SDG&E agree that Item 4 is redundant 

with the three priority levels established by Rule 18A for correcting 

nonconformances. 

The only substantive difference between the two proposals is the time 

period for correcting certain types of priority Level 2 nonconformances. The 

CIP Coalition’s proposal (Contested Proposal 3A) retains the existing 

requirement to correct Level 2 nonconformances within 59 months. SDG&E’s 

proposal (Contested Proposal 3B) also retains a general requirement to correct 

Level 2 nonconformances within 59 months. However, if the nonconformance 

 

32 Cox, a member of the CIP Coalition, abstains from taking a position on 

Contested Proposals 3A and 3B. 

33 The CIP Coalition’s and SDG&E’s proposals to revise Rule 18A include the 

consensus revisions to Rule 18 adopted previously in today’s decision. 

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either compromises worker safety or creates a fire risk in an Extreme or Very 

High Fire Threat Zone in Southern California, SDG&E’s proposal would require 

the safety hazard to be corrected within 12 months. For ease of reference, the 

proposed revisions with respect to the time period for correcting Level 2 

nonconformances are set forth below: 

CIP Coalition Contested Proposal 3A

Time period for correction to be determined at the time of 

identification by a qualified company representative, but not 

to exceed 59 months. 

SDG&E Contested Proposal 3B

Time period for correction to be determined at the time of 

identification by a qualified company representative, but not to 

exceed: (1) 12 months for nonconformances that compromise 

worker safety, (2) 12 months for nonconformances that create a 

fire risk and are located in an Extreme or Very High Fire Threat 

Zone in Southern California, and (3) 59 months for all other 

Level 2 nonconformances. 

The compete text of the proposed revisions to Rule 18A under Contested 

Proposals 3A and 3B is contained in Appendix A of today’s decision. 

The CIP Coalition and SDG&E believe their proposals will reduce costs by 

streamlining Rule 18A requirements. However, SDG&E’s proposal could 

accelerate costs compared to the CIP Coalition’s proposal for those companies 

that would take longer than SDG&E’s proposed 12 months to correct Level 2 

nonconformances that create a worker-safety risk or fire risk. 

6.3.2. Position of the Parties 

The CIP Coalition asserts that its proposal (Contested Proposal 3A) will 

eliminate duplicative, vague, and/or unnecessary obligations in Rule 18A. For 

example, Rule 18A currently requires that prior to work being performed, 

companies must document the current status of the nonconformance, including 

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whether it is in a specified Fire Zone. The CIP Coalition posits that the required 

documentation provides no safety benefits, delays work, and increases costs. 

The CIP Coalition opposes SDG&E’s proposal to reduce the deadline from 

59 months to 12 months for correcting nonconformances that compromise 

worker safety or create a fire risk in an Extreme or Very High Fire Threat Zone in 

Southern California. The CIP Coalition states that SDG&E’s proposed 12-month 

requirement hinges on two vague terms (i.e., “compromise” and “fire risk”) 

which could be interpreted to mean that any nonconformance would require 

corrective action within 12 months, thus eliminating the entire rationale for 

having a 59-month range in the first place. 

The CIP Coalition submits that SDG&E’s proposed 12-month deadline is 

unnecessary because, under the CIP Coalition’s proposal, any nonconformance 

categorized as a Level 2 priority would have to be corrected within a timeframe 

commensurate with the risk, not to exceed 59 months. Thus, the fact that the 

Level 2 priority has a range of 0-59 months does not mean that a company can 

wait 59 months to repair every Level 2 nonconformance. 

The CIP Coalition also argues that SDG&E’s proposal unfairly imposes 

obligations on CIPs but not electric utilities. This is because Rule 18A exempts 

electric utilities that have maintenance programs that comply with GO 165, such 

as PG&E, SCE, and SDG&E. 

Turning to a separate matter, the CIP Coalition notes that SCE proposes 

significant edits to GO 95, summarized below, that would move the content of 

Rule 18A to other parts of GO 95. The CIP Coalition cannot endorse SCE’s 

changes that were submitted for the first time in SCE’s opening brief. 

The CIP Coalition’s proposal is supported by CPSD, LADWP, PacifiCorp, 

PG&E, SCE, and Sierra Pacific. In general, the supporters of the CIP Coalition’s 

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proposal believe it will streamline Rule 18A, clarify its requirements, and enable 

companies to prioritize maintenance work based on local conditions and 

available resources. This should help companies to manage their maintenance 

programs more efficiently. 

PG&E and SCE oppose SDG&E’s proposed 12-month timeframe for 

correcting certain Level 2 safety hazards for the following reasons: (1) Rigid 

timeframes hinder the ability to prioritize maintenance activities based on local 

conditions and available resources; (2) timeframes for corrective actions should 

not be included in a General Order, since maintenance timeframes are based on 

judgments made in the field and can change depending on local conditions, 

technological advancements, and process improvements; and (3) if future 

changes to corrective maintenance timeframes are desirable, parties would have 

to seek a modification to GO 95, a process that could take years. 

Although SCE supports the CIP Coalition’s proposal, SCE recommends 

moving the contents of Rule 18A, as modified by the CIP Coalition’s proposal, to 

Rules 12.2 and 23.3 and a new Appendix J. SCE’s proposed edits were presented 

for the first time in its opening brief. 

SDG&E generally supports the CIP Coalition’s proposed revisions to 

Rule 18A. However, SDG&E opposes the retention of the current deadline of 

59 months for correcting all Level 2 nonconformances. By definition, Level 2 

nonconformances can have high safety risks.34 SDG&E believes that a 

nonconformance which either compromises worker safety or creates a fire risk in 

 

34 Under the existing Rule 18A and both 18A proposals, Level 2 priorities are 

“[v]ariable (non-immediate high to low) safety and/or reliability risk.” 

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an Extreme or Very High Fire Threat Zone in Southern California should be 

corrected within 12 months as required by SDG&E’s proposal, not 59 months as 

allowed by the CIP Coalition’s proposal. SDG&E states that 12 months is more 

than enough time to cure safety hazards. 

SDG&E disagrees with the CIP Coalition’s claim that SDG&E’s proposal 

could be interpreted to mean any alleged nonconformance would require 

corrective action within 12 months, thus eliminating the rationale for having a 

59 month range. SDG&E responds that for each Level 2 (high to low, but nonimmediate) nonconformance, the same two or three questions need to be asked. 

First, does it compromise worker safety? SDG&E believes that many types of 

GO 95 nonconformances would not. Second, does it create a fire risk? If so, is it 

located in an Extreme or Very High Fire Threat Zone in Southern California? 

SDG&E submits that these questions can be answered by trained personnel in 

the same way they are called upon to decide if particular safety hazards and 

GO 95 nonconformances are Level 1, Level 2, or Level 3. 

SDG&E disputes the CIP Coalition’s assertion that SDG&E seeks to impose 

a tougher requirement on CIPs than electric utilities. SDG&E states that its 

Commission-authorized GO 165 maintenance plan requires SDG&E to correct all 

nonconformances within 12 months. Thus, SDG&E is proposing a less stringent 

standard for CIPs than what currently applies to SDG&E. 

LA County supports SDG&E’s proposal to correct within 12 months 

nonconformances that compromise worker safety and/or create a fire risk in the 

high fire-threat areas of Southern California. Conversely, LA County opposes 

the CIP Coalition’s proposal to allow up to 59 months to correct these safety 

hazards. There could be several high-wind events over 59 months, and the 

possibility that poles will fail is increased the longer that violations linger. Thus, 

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the CIP Coalition’s proposal, if adopted, would decrease safety and might cause 

additional wildfires. 

IBEW 1245 supports both proposals. If the Commission agrees to a 

59-month deadline, IBEW 1245 recommends that it be made clear that companies 

which fail to correct GO 95 violations after 59 months will face serious sanctions. 

IBEW 1245 further recommends that the Commission require expedited 

correction of any violation of climbing space. 

CMUA supports the provision in both proposals that requires 

communication companies to have robust maintenance programs. 

6.3.3. Discussion 

The CIP Coalition's and SDG&E’s proposed revisions to Rule 18A are the 

same in all material respects with one exception discussed below. Both 

proposals retain the following core elements of Rule 18A adopted by the Phase 1 

Decision: 

• The obligation to maintain overhead facilities in good 

condition; to take corrective actions; and to keep auditable 

records of maintenance programs and corrective actions. 

• Three priority levels for taking corrective actions, the factors on 

which priorities must be based, deadlines within each priority 

level for completing corrective actions, and situations when the 

deadlines for completing corrective actions may be extended. 

• The obligation to correct Level 1 nonconformances 

immediately. Level 1 consists of “Immediate safety and/or 

reliability risk with high probability for significant impact.” 

• The ability of electric utilities with maintenance programs 

established under GO 165 to rely on these programs, provided 

these programs are consistent with Rule 18A. 

The revisions to Rule 18A that are common to both proposals are intended 

to streamline record keeping requirements and to remove unnecessary and 

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redundant provisions. There is no opposition to these proposed revisions. We 

hereby adopt them. Among other things, the adopted revisions will clarify the 

requirements of Rule 18A, which should enhance the ability of companies to 

manage their maintenance programs efficiently and thereby reduce safety 

hazards and costs. 

 The only substantive difference between the two proposals is the deadline 

for correcting Level 2 nonconformances. The CIP Coalition’s proposal would 

retain the current requirement in Rule 18A to correct all Level 2 

nonconformances within 59 months. SDG&E’s proposal, on the other hand, 

would establish two deadlines for correcting Level 2 nonconformances: 

• 12 months for nonconformances that either compromise 

worker safety or create a fire hazard in an Extreme or Very 

High Fire Threat Zone in Southern California. 

• 59 months for all other Level 2 nonconformances. 

We find that it is reasonable to adopt SDG&E’s proposal because it 

provides a higher level of worker safety and fire safety. The adopted text of 

Rule 18A is contained in Appendix B of today’s decision, and includes the 

consensus revisions to Rule 18A that were adopted previously in today’s 

decision.35 

We will incorporate into Rule 18A the fire-threat maps that we adopt later 

in today’s decision to designate high fire-threat areas in Southern California for 

the purpose of implementing Rule 18A. We will also modify Rule 18A so that 

 

35 The adopted revisions to Rule 18A correct two typos in SDG&E’s proposal. One 

correction replaces the semicolon with a period in the bullet in Section 2a that begins 

with “Direct or potential....” The second correction replaces a semicolon with a 

colon in the sentence in Section 2a that begins with “Time period for correction....” 

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the remedial action for correcting certain types of nonconformances specified in 

Rule 18A(1)(c) applies to both electric utilities and communications companies.36 

We emphasize that the deadlines for correcting nonconformances adopted by 

today’s decision do not relieve CIPs and electric utilities of their obligation to 

correct nonconformances sooner if doing so is necessary to protect public safety 

or maintain reliability. 

Today’s decision retains the current provision in Rule 18A that electric 

utilities which have established maintenance programs under GO 165 “that are 

consistent with the purpose of Rule 18” shall continue to follow their GO 165 

programs.37 We interpret this provision to mean that the deadlines for corrective 

actions under GO 165 maintenance programs cannot exceed the deadlines for 

corrective actions in Rule 18, as revised by today’s decision. 

We are not persuaded by the argument made by several parties that it is 

unnecessary to set deadlines for correcting Level 2 nonconformances other than 

59 months. Although we generally agree that companies should have flexibility 

to prioritize the repair of most Level 2 nonconformances within an overall 

window of 59 months, we also conclude that conditions which compromise 

worker safety or increase fire risk in the high fire-threat areas of Southern 

California should not be allowed to persist for up to 59 months. We concur with 

SDG&E’s assessment that the best way to ensure that threats to worker safety 

 

36 The Rule 18A(1)(c) adopted by today’s decision states: “Where a communications 

company’s or an electric utility’ actions result in GO nonconformances for another 

entity, that entity’s remedial action will be to transmit a single documented notice of 

identified nonconformances to the communications company or electric utility for 

compliance.” 

37 D.09-08-029 at 20. 

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and fire safety are corrected within a reasonable timeframe is to establish an 

explicit deadline for doing so in Rule 18A. 

We decline to adopt SCE’s proposal to move the contents of Rule 18A to 

other parts of GO 95 and a new Appendix J. SCE’s proposal was not presented 

at the Phase 2 workshops and, therefore, falls outside the scope of today’s 

decision. 

6.4. Contested Proposal 4 re: GO 95, Rule 18C 

6.4.1. Summary of Proposal 

MGRA proposes to add a new Rule 18C to GO 95 that would require 

electric utilities to develop plans to prevent power-line fires when strong winds 

exceed the structural limits for overhead facilities in areas of high fire risk during 

periods of high fire danger. The text of the proposed Rule 18C is contained in 

Appendix A of today’s decision. MGRA did not provide a cost estimate for its 

proposal, but MGRA believes the cost would be far outweighed by the benefits 

of avoided catastrophic wildfires. 

6.4.2. Position of the Parties 

MGRA states that the risk of power lines igniting catastrophic wildfires 

during windstorms can be greatly reduced by contingency planning that 

includes the following three elements: (1) defining reasonably foreseeable wind 

hazards, (2) identifying the occurrence of hazardous winds, and (3) planning a 

response. MGRA submits that statistical analysis of historical weather data can 

be used to estimate the maximum worst case wind load on power lines. Using 

this information, appropriate countermeasures can be planned. 

MGRA suggests that fire-prevention plans consist of engineering 

countermeasures, operational countermeasures, or both. Engineering 

countermeasures could include hardening of power-line facilities in areas where 

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it is foreseeable that strong winds may exceed the structural design standards for 

overhead facilities set forth in GO 95. Operational countermeasures could be 

employed when winds exceed the structural design limits, and might include 

revised settings for reclosers and shutting off power. 

MGRA recognizes that operational countermeasures can cause physical 

and financial harm to residents. Therefore, such countermeasures should only 

be used when much greater harm from power-line fires is the likely consequence 

of inaction. Ideally, this should be determined by a cost-benefit analysis. 

MGRA emphasizes that its proposed Rule 18C is focused on solving the 

potential in Southern California for high winds to cause multiple power-line 

fires, as observed in October 2007. MGRA is not aware of a similar wind hazard 

in Northern California, but MGRA recommends that the Commission obtain an 

expert opinion on this matter. 

LA County supports MGRA’s proposal. LA County asserts that the need 

for the proposed rule is demonstrated by the multiple large fires that ignited 

simultaneously throughout Southern California during Santa Ana wind events 

in 2003 and 2007. These fires taxed fire-fighting resources, resulted in large scale 

evacuations, and caused significant loss of life and property. LA County opines 

that shutting off power should only be used as a last resort, but that utilities need 

this option when faced with extreme circumstances. 

MGRA’s proposal is opposed by CMUA, the CIP Coalition, LADWP, 

PacifiCorp, PG&E, SCE, SDG&E, and Sierra Pacific for the following reasons. 

First, the opponents state that fire-prevention plans do not belong in GO 95, 

which is limited to construction and maintenance standards. Second, the 

proposed rule is unnecessary because electric utilities are already required by 

GO 166 to plan for major emergencies. Third, electric utilities cannot accurately 

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predict hazardous wind conditions or power-line fires. Consequently, the 

proposed rule is impossible to implement. Fourth, the only sure way to prevent 

strong winds from igniting power-line fires is to shut off power, but this option 

was rejected by D.09-09-030. Finally, the proposed fire-prevention plans would 

be costly to develop with no commensurate benefits. 

CMUA notes that the Phase 1 Scoping Memo determined that “[t]his 

rulemaking proceeding will not decide issues that will be resolved in the 

Commission’s decision on SDG&E’s Application (A.) 08-12-021 filed on 

December 22, 2008, in which SDG&E asked the Commission to review SDG&E’s 

plan to shut off power to high fire risk areas during certain extreme weather 

conditions.”38 Thus, MGRA’s proposal is outside the scope of this proceeding to 

the extent it calls for electric utilities to develop plans to shut of power in 

response to high-wind conditions. 

PacifiCorp and Sierra Pacific raise additional concerns. They represent 

that strong winds in their service territories typically occur during the winter as 

part of snowstorms and rainstorms. Consequently, MGRA’s proposal is unlikely 

to reduce fire risks in their service territories. 

SDG&E is concerned that MGRA’s proposal would conflict with 

D.09-09-030, which ordered SDG&E to convene a collaborative stakeholder 

process to develop a fire-prevention plan. Thus, there is no need to require 

SDG&E to develop a contingency plan to deal with wind and fire dangers 

because SDG&E is already doing so pursuant to D.09-09-030. 

 

38 Phase 1 Scoping Memo dated January 6, 2009, at 5. 

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6.4.3. Discussion 

We agree with MGRA that electric utilities should develop and implement 

fire-prevention plans to address situations where it is reasonably foreseeable that 

strong winds may exceed the structural limits of overhead electric facilities 

during periods of high fire danger. The need for fire-prevention plans is 

demonstrated by the events of October 2007 when strong Santa Ana winds in 

Southern California caused power lines to ignite wildfires at multiple locations. 

Together, these power-line fires burned more than 334 square miles and caused 

immense devastation and disruption, including the largest evacuation in 

California’s history.39 It is virtually certain that Southern California will continue 

to experience Santa Ana windstorms. Thus, there is a grave and ongoing risk 

that Santa Ana windstorms will again cause power lines to ignite catastrophic 

wildfires unless electric utilities plan and prepare for such events. 

For the preceding reasons, we will require investor-owned electric utilities 

(electric IOUs) in Southern California to develop plans to reduce the risk of 

severe windstorms igniting power-line fires during periods of high fire danger. 

Consistent with the Phase 1 Decision, we define Southern California as 

consisting of Imperial, Santa Barbara, Ventura, Los Angeles, Orange, San Diego, 

Riverside, and San Bernardino Counties.40 Each electric IOU in Southern 

California shall complete its initial fire-prevention plan by December 31, 2012, 

and file and serve a copy of its plan via a Tier 1 compliance advice letter. 

 

39 California Fire Siege 2007 – an Overview, at 20, 27, 58, and Appendices II and III. 

40 D.09-08-029, Ordering Paragraph 1. Today’s decision adds Imperial County to the 

list of counties that comprise Southern California. 

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Unlike Southern California, the need for electric utilities to develop 

fire-prevention plans in Northern California is not clear cut.41 To our knowledge, 

there has never been an instance in Northern California where strong winds 

have caused power lines to ignite large-scale wildfires. This is consistent with 

PacifiCorp and Sierra Pacific’s statement that strong winds in their service 

territories are confined to winter months when the risk of wildfires is low.42 

Nevertheless, we remain concerned about the risk of wind-caused 

power-line fires in Northern California. Both the FRAP Map and the Reax Map 

discussed later in today’s decision show millions of acres in Northern California 

where there is a high fire threat. In order to determine the magnitude of the risk, 

we will require electric IOUs in Northern California to do the following: 

• Identify their overhead power-line facilities that are located in 

high fire-threat areas on the interim fire-threat maps adopted 

later in today’s decision. 

• Make a good-faith effort to obtain historical records of Red 

Flag Warnings issued by the National Weather Service that 

applied to areas occupied by facilities identified in the first 

bullet. 

• Make a good-faith effort to obtain historical wind records of 

Remote Automatic Weather Stations located within 25 miles of 

the facilities identified in the first bullet. 

 

41 For the purpose of today’s decision, we define Northern California as all counties in 

California except Imperial, Santa Barbara, Ventura, Los Angeles, Orange, San Diego, 

Riverside, and San Bernardino Counties. 

42 Multi-Jurisdictional Electric Utilities’ Opening Brief at 9 - 10. 

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• Use the information from the second and third bullets to 

estimate how often, if ever, 3-second wind gusts occur during a 

Red Flag Warning that exceed the maximum working stresses 

specified in GO 95, Section IV, for facilities identified in the 

first bullet. 

Electric IOUs may pool their resources and hire consultants to carry out 

the above tasks. Electric IOUs may also seek to recover the reasonable costs they 

incur to carry out the above tasks in accordance with the procedures specified 

later in today’s decision. 

An electric IOU that serves Northern California shall develop a 

fire-prevention plan if the utility determines, after completing the previously 

identified tasks, that it has overhead power-line facilities in a high fire-threat 

area where it is reasonably foreseeable that the probability of 3-second wind 

gusts exceeding the maximum working stresses for such facilities during a 

Red Flag Warning is 3% or more during a 50-year period. Electric IOUs in 

Northern California shall complete the above tasks and prepare a fire-prevention 

plan, if necessary, no later than December 31, 2012. Electric IOUs in Northern 

California shall also file a Tier 1 compliance advice letter by December 31, 2012, 

that either (i) contains a copy of their fire-prevention plan, or (ii) provides notice 

that a fire-prevention plan is not required by today’s decision. 

Consistent with MGRA’s proposal, the fire-prevention plans shall address 

situations where all three of the following conditions occur simultaneously: 

(1) 3-second wind gusts exceed the structural or mechanical design standards for 

the affected overhead power-line facilities, (2) these wind gusts occur during a 

period of high fire danger, and (3) the affected facilities are located in a high 

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fire-threat area.43 We define “structural or mechanical design standards” as the 

maximum working stresses set forth in GO 95, Section IV. We define “period of 

high fire danger” as the period covered by a Red Flag Warning issued by the 

United States National Weather Service. We define high fire-threat areas as areas 

designated as such on the fire-threat maps adopted later in today’s decision. 

A utility’s fire-prevention plan must specify (A) how the utility will 

identify the occurrence of 3-second gusts that exceed the structural or mechanical 

design standards for overhead power-line facilities; and (B) the countermeasures 

the utility will implement to mitigate the threat of power-line fire ignitions. 

Today’s decision does not require any particular countermeasures. Each utility 

should implement the countermeasures it deems appropriate for its 

circumstances. We anticipate that countermeasures will include both operational 

responses to high winds (e.g., adjusting the settings on automatic re-closers) and 

physical changes to utility facilities (e.g., strengthening facilities). Some 

countermeasures can likely be implemented relatively quickly, such as 

operational countermeasures, while other countermeasures that involve physical 

alternations to overhead power-line facilities may take years or decades to 

implement completely. 

Any electric IOU that intends to shut off power as part of its 

fire-prevention plan must file an application for authority to do so. The 

application shall demonstrate with a cost-benefit analysis developed in 

accordance with the guidance provided by D.09-09-030 that the benefits of 

 

43 Electric utilities may develop fire-prevention plans that address a broader array of 

situations than required by today’s decision. 

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shutting of power in terms of a net reduction in wildfire ignitions outweigh the 

substantial costs, burdens, and risks that shutting off power would impose on 

customers and communities affected by the shut off.44 The application must also 

include mitigation measures to reduce or eliminate the inevitable adverse 

impacts caused by shutting off power. Special effort should be placed on 

mitigating the adverse impacts on people with disabilities, providers of essential 

services, and schools. An electric IOU may not shut off power as a part of its 

fire-prevention plan until the Commission has granted authority to do so. 

We agree with the position advocated by several parties that the 

requirement to prepare fire-prevention plans does not belong in GO 95, which 

sets forth rules for the design, construction, and maintenance of overhead 

facilities. We conclude that the requirement to prepare fire-prevention plans is 

better suited to GO 166, which specifies standards for emergency planning and 

restoration of service following a disaster. Today’s decision adds a new 

Standard 1.E (Fire Prevention) to GO 166, and the existing Standards 1.E (Safety 

Considerations) through 1.I (Plan Update) are renumbered 1.F through 1.J. The 

text for the new Standard 1.E is contained in Appendix B of today’s decision. 

All of the provisions of GO 166 shall apply to fire-prevention plans. For 

example, electric IOUs will have to review and update their fire-prevention plans 

annually, submit revised plans to the Commission, and conduct an annual 

exercise using the procedures set forth in the fire-prevention plans.45 

 

44 D.09-09-030 at 58 - 61. 

45 GO 166, Standards 1.J (renumbered), 3, and 11. 

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Several parties argue that it is unnecessary to require electric utilities to 

prepare fire-prevention plans because electric utilities are already required by 

GO 166 to prepare for major emergencies. We disagree. GO 166 was adopted 

more than 20 years ago, yet only SDG&E appears to have a fire-prevention plan 

in effect or under development. Given the general lack of vigilance, we conclude 

that GO 166 needs to be revised to ensure that electric IOUs prepare for 

foreseeable extreme fire-weather events. 

We also disagree with SDG&E’s argument that there is no need to require 

SDG&E to prepare a fire-prevention plan because SDG&E is already doing so 

pursuant to D.09-09-030. In D.09-09-030, the Commission authorized, but did 

not require, SDG&E to submit a fire-prevention plan.46 In contrast, today’s 

decision requires SDG&E to prepare a fire-prevention plan.47 

Several parties mistakenly claim that D.09-09-030 rejected the option of 

shutting off power to prevent fires. Today’s decision directs electric IOUs that 

intend to shut off power during extreme fire-weather events to file applications 

for authority to do so. This is consistent with the Commission’s determination in 

D.09-09-030 that SDG&E should be allowed to file another application for 

authority to shut-off power, provided SDG&E’s power shut-off plan meets 

certain criteria specified in D.09-09-030.48 

 

46 D.09-09-030, Ordering Paragraphs 2 and 3. 

47 D.09-09-030 contains specific requirements regarding the development and content 

of SDG&E’s fire-prevention plan. All of the requirements adopted by D.09-09-030 

for SDG&E continue to apply. 

48 D.09-09-030 at 56 – 59 and Ordering Paragraph 3. 

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CMUA mistakenly claims that MGRA’s proposed fire-prevention plan is 

outside the scope of this proceeding pursuant to the Phase 1 Scoping Memo 

dated January 6, 2009. There, the Assigned Commissioner determined that 

“[t]his rulemaking proceeding will not decide issues that will be resolved in the 

Commission’s decision on SDG&E’s Application (A.) 08-12-021...in which 

SDG&E asks the Commission to review SDG&E’s plan to shut off power to high 

risk fire areas during certain extreme weather conditions.49” Today’s decision 

does not decide or re-visit any issues that were resolved in D.09-09-030, the 

Commission’s decision regarding A.08-12-021. Rather, today’s decision adopts 

several measures that are consistent with D.09-09-030. 

We decline to exempt PacifiCorp and Sierra Pacific from the requirements 

in today’s decision pertaining to fire-prevention plans because strong winds in 

their service territories purportedly occur only in winter months when the risk of 

wildfires is low. The events of October 2007 demonstrate that strong winds can 

cause power lines to ignite catastrophic wildfires. In order to protect public 

safety, we conclude that it is necessary for all electric IOUs, including PacifiCorp 

and Sierra Pacific, to assess the risk of wind-ignited power-line fires during 

extreme fire-weather events and to develop fire-prevention plans in areas where 

it is determined that there is a relatively high risk for such fires. 

Several parties express concern that electric utilities cannot predict 

hazardous wind conditions or power-line fires. Today’s decision does not 

require such predictions. Rather, today’s decision requires electric IOUs to 

monitor weather stations to determine when wind conditions are likely to exceed 

 

49 Phase 1 Scoping Memo dated January 6, 2010, at page 5. 

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GO 95 design standards during extreme fire-weather conditions and to 

implement countermeasures to reduce the likelihood of power-line fires during 

these conditions. SDG&E is already well on its way to achieving these objectives. 

As a final matter, we emphasize that today’s decision does not affect 

electric IOUs’ authority under § 451 and § 399.2(a) to shut off power in 

emergency situations when necessary to protect public safety. This is consistent 

with the Commission’s determination in D.09-09-030 “that SDG&E may need to 

shut off power in order to protect public safety if Santa Ana winds exceed the 

design limits for SDG&E’s system and threaten to topple power lines onto tinder 

dry brush.50” Any decision by utilities to shut off power under their existing 

statutory authority may be reviewed by the Commission pursuant to its broad 

jurisdiction over matters regarding the safety of public utility operations and 

facilities. The Commission may decide at that time whether a utility’s decision to 

shut off power was reasonable and qualifies for an exemption from liability 

under Tariff Rule 14.51

6.5. Contested Proposal 5 re: GO 95, Rule 31.1 

6.5.1. Summary of Proposal 

Rule 31.1 of GO 95 requires electric utilities and CIPs to design, construct, 

and maintain their systems in accordance with the intended use of the systems 

and the conditions under which the systems will be operated. Rule 31.1 further 

requires that for all particulars not specified in GO 95, electric utilities and CIPs 

 

50 D.09-09-030 at 60. 

51 Most electric utilities have a Tariff Rule 14 or similar tariff rule that states the electric 

utility will not be held liable for an interruption in service caused by inevitable 

accidents, act of God, fire, strikes, riots, war, or any other cause outside of its control. 

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must design, construct, and maintain their systems in accordance with accepted 

good practice for the given local conditions known at the time. 

PG&E, SCE, and SDG&E (the “Joint Utilities”) propose to revise Rule 31.1 

to state that electric utilities and CIPs will be in compliance with Rule 31.1 if they 

design, construct, and maintain their facilities in accordance with all particulars 

specified in GO 95 or, if particulars are not specified, in accordance with 

accepted good practice. The also seek to revise Rule 31.1 to state that “accepted 

good practice” will be determined on a case-by-case basis “with reference to any 

of the practices, methods, and acts engaged in or approved by a significant 

portion of the relevant industry, or which may be expected to accomplish the 

desired result with regard to safety and reliability at a reasonable cost.” The text 

of the proposed revisions to Rule 31.1 is contained in Appendix A of today’s 

decision. 

6.5.2. Position of the Parties 

The Joint Utilities’ proposal is intended to limit CPSD’s ability to allege 

that utilities have violated Rule 31.1 without having to identify the specific 

design, construction, or maintenance standard that was violated. 

The proposal is supported by the CIP Coalition, CMUA, PacifiCorp, and 

Sierra Pacific. These parties agree with the Joint Utilities that CPSD has used the 

existing Rule 31.1, with its vague directive to furnish “safe, adequate, and proper 

service,” as a catch-all provision to allege violations without citing any particular 

General Order, specific industry practice, or engineering standard. 

The proposed revisions to Rule 31.1 would clarify that CIPs and electric 

utilities must design, construct, and maintain their facilities in accordance with 

the standards specified GO 95 and, if no standards are specified, in accordance 

with accepted good practice. The “accepted good practice” standard is currently 

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in Rule 31.1, but is not defined. The proposal defines “accepted good practice” 

so that CIPs and electric utilities will know what requirements they must meet to 

comply with GO 95. The proposal reduces the risk that CPSD will find a 

“violation” of a standard that is not described in GO 95. It will also help ensure 

that companies follow industry best practices for system reliability and safety. 

CPSD is the only party opposed to the proposal. CPSD currently uses 

Rule 31.1 to cite utilities for unsafe conditions not covered by other rules. CPSD 

contends that the proposal will diminish public safety by preventing the 

Commission from citing companies for unsafe conditions. Although utilities 

have long complained that Rule 31.1 lacks sufficient specificity to provide proper 

notice as to what constitutes a violation, the Commission and the courts have 

rejected these arguments as often as the utilities have made them.52 

CPSD submits that the Commission has always relied on general 

principles to ensure the safe operation of utility systems. For example, Rule 12.2 

of GO 128 requires facilities to “be maintained in such condition as to secure 

safety to workmen and the public in general.” Rule 17.1 of GO 128 requires 

facilities to be “maintained in a condition which will provide adequate service 

and secure safety to workmen, property and the general public.” And Pub. Util. 

Code § 451 requires utilities to furnish “just and reasonable service, 

instrumentalities, equipment, and facilities as are necessary to promote the 

safety, health, comfort, and convenience of its patrons, employees, and the 

public.” 

 

52 See, e.g., D.99-04-029, D.04-09-062, and Cingular Wireless v. CPUC (2006) 140 

Cal.App.4th 718. 

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CPSD maintains that defining “accepted good practice” as any practice 

approved by a significant portion of the relevant industry would allow utilities 

to collude to develop whatever design, construction, and maintenance practices 

they see fit. Then, if a utility follows these self-prescribed practices, the utility 

would be deemed in compliance with GO 95 and avoid any liability. Moreover, 

the proposed definition of “accepted good practice” is vague as to the meaning 

of a “significant portion of the relevant industry.” For example, it is unclear 

whether this refers to California or the entire United States. The way it is 

written, “accepted good practice” would mean whatever utilities want it to 

mean. 

Finally, CPSD believes the proposed revisions to Rule 31.1 fall outside the 

scope of this proceeding, as the proposal would reduce the utilities’ liability, both 

at the Commission and in civil courts, by narrowing the circumstances in which 

Rule 31.1 may be used to cite utilities for unsafe conditions. 

6.5.3. Discussion 

We agree with the Joint Utilities that Rule 31.1 does not provide clear 

guidance regarding what constitutes compliance with the design, construction, 

and maintenance standards in GO 95, which hinders the ability of electric 

utilities and CIPs to comply with the General Order. This is contrary to the 

Commission’s intent that GO 95 should be “capable of definite interpretation 

sufficient to form the basis of working specifications for overhead electric line 

construction.53” 

 

53 GO 95, Preface, at page x. 

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The Joint Utilities’ proposed revisions to Rule 31.1 will clarify the 

Commission’s expectations about what constitutes compliance with GO 95 by 

adding the following paragraph and note to the Rule 31.1 that state: 

For all particulars specified in this General Order, a supply or 

communications company is in compliance with this rule if it 

designs, constructs and maintains a facility in accordance with 

such particulars. For particulars not specified in this General 

Order, a supply or communications company is in 

compliance with this rule if it designs, construct and 

maintains a facility in accordance with accepted good practice. 

(Emphasis added.)54

Note: The standard of accepted good practice should be 

applied on a case by case basis. For example, the application 

of “accepted good practice” may be aided by reference to any 

of the practices, methods, and acts engaged in or approved by 

a significant portion of the relevant industry, or which may be 

expected to accomplish the desired result with regard to 

safety and reliability at a reasonable cost. 

We believe the above revisions to Rule 31.1 will improve public safety by 

clarifying the compliance obligations of electric utilities and CIPs under GO 95. 

It is beyond dispute that complying with these standards should minimize the 

safety hazards – including fire risks - associated with overhead power lines and 

aerial CIP facilities. For these reasons, we conclude that it is in the public interest 

to adopt the proposed revisions to Rule 31.1, but with one modification. 

Our one modification is to clarify that the revised Rule 31.1 requires 

electric utilities and CIPs to design, construct, and maintain their facilities for 

their intended use and known local conditions. If the intended use or known 

 

54 Today’s decision corrects a possible oversight in the Phase 2 Workshop Report by 

changing the word “Order” to the term “General Order.” 

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local conditions require a higher standard than the particulars specified in GO 95 

“to enable the furnishing of safe, proper, and adequate service,”55 then the 

company must follow the higher standard.56 

We do not share CPSD’s concern that the adopted revisions to Rule 31.1 

will limit the Commission’s ability to penalize companies for unsafe conditions. 

As stated previously, our intent in adopting the revisions to Rule 31.1 is to clarify 

the compliance obligations of electric utilities and CIPs under GO 95. By 

clarifying these obligations, we also facilitate enforcement of these obligations. 

The revised Rule 31.1 will still be available to CPSD as an enforcement tool 

whenever a company has failed to comply with GO 95 or accepted good practice. 

There is no effect on the Commission’s existing authority to determine what 

constitutes compliance with GO 95 on a case-by-case basis in light of specific 

facts and circumstances. 

CPSD asserts that the adopted revisions will weaken safety requirements 

by allowing CIPs and electric utilities to collude to establish whatever “accepted 

good practices” they see fit. We disagree. As noted earlier, the Commission may 

determine what constitutes accepted good practice on a case-by-case basis. 

Regardless, we believe it is unlikely that CIPs and electric utilities would collude 

to deliberately weaken safety standards. 

 

55 Rule 31.1, first paragraph. 

56 In its comments on the proposed decision, CDSP notes that the proposed decision’s 

revisions to the text of Rule 31.1 did not convey our intent that if an intended use or 

a known local condition requires a more rigorous standard than the particulars 

specified in GO 95 to enable the furnishing of safe, proper, and adequate service, the 

company must follow the higher standard. Today’s decision corrects this oversight. 

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Finally, CPSD mistakenly contends that the adopted revisions to Rule 31.1 

fall outside the scope of this proceeding (fire safety mitigation). The Phase 2 

Scoping Memo allows “matters with a direct nexus to this proceeding”57

including proposals that “improve the meaning and clarity of those provisions in 

the General Orders that pertain to fire safety.”58 The adopted revisions to 

Rule 31.1 meet these criteria. 

6.6. Contested Proposals 6A – 6D re: GO 95, Rules 31.2 

and 80.1A 

Rule 31.2 of GO 95 requires power lines and communication lines to be 

inspected frequently and thoroughly. Electric utilities fulfill their inspection 

obligation in accordance with the standards in GO 165. There are no similar 

standards in the General Orders for the inspection of CIP facilities. 

The Phase 2 Workshop Report presents five contested proposals to revise 

Rule 31.2 and other parts of GO 95 to incorporate inspection requirements for 

CIP facilities. Four of these proposals (Contested Proposals 6A through 6D) are 

addressed immediately below. The fifth proposal (Contested Proposal 6E) is 

addressed later in today’s decision. 

6.6.1. Summary of Proposals 6A and 6B 

The members of the CIP Coalition submitted two proposals. Proposal 6A, 

also known as the CIP-1 proposal, was submitted by CCTA, Comcast, CTIA, 

NextG, Sprint, Sunesys, Time Warner, T-Mobile, tw telecom, and Verizon 

(together, “the CIP-1 Proponents”). The CIP-1 proposal would require (1) patrol 

 

57 Phase 2 Scoping Memo at 8. 

58 Phase 2 Scoping Memo at 12. 

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inspections59 every three years for CIP facilities on joint-use poles60 or one pole 

length away in high fire-threat areas61 of the state; (2) detailed inspections62 every 

nine years for these same facilities; and (3) records of all inspections. 

Proposal 6B, also known as the CIP-2 proposal, was submitted by AT&T, 

Frontier Communications, and the Small LECs (together, “the 

CIP-2 Proponents”). The CIP-2 proposal would require (1) patrol inspections 

every five years for CIP facilities on joint-use poles or one pole length away in 

high fire-threat areas of the state; and (2) records of all inspections. The CIP-2 

proposal does not require detailed inspections. 

The proposed revisions to Rule 31.2 under the CIP-1 proposal and the 

CIP-2 proposal are shown in Appendix A of today’s decision. There will be 

additional costs associated with the CIP-1 and CIP-2 proposals, but the amount is 

unknown. The CIP Coalition states that because their proposals are limited to 

areas where the potential fire risk is highest, their proposals strike a proper 

balance between the costs and benefits of inspections. 

6.6.2. Summary of Proposals 6C and 6D 

Proposal 6C was submitted by CPSD. This proposal would establish the 

following statewide standards for the inspection of CIP facilities located on 

 

59 Patrol inspections are simple visual inspections that are designed to identify obvious 

structural problems and hazards. 

60 Today’s decision defines a joint-use pole as a utility pole that has both CIP facilities 

and power lines attached. 

61 The fire-threat maps that should be used to designate high fire-threat areas are 

addressed later in today’s decision as part of Contested Proposal 14. 

62 Detailed inspections are careful visual inspections using binoculars and measuring 

devices, as appropriate. 

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joint-use poles and CIP-only poles within one span of joint-use poles: (1) oneyear patrol inspection cycle for urban areas; (2) two-year patrol inspection cycle 

for rural areas; (3) one-year patrol inspection cycle for rural areas in the high firethreat areas of Southern California; and (4) ten-year detailed inspection cycle for 

the CIP facilities identified in (1) through (3). The inspection cycle for all other 

CIP facilities would be determined by the CIPs based on the following factors: 

(a) Proximity to electric facilities, (b) terrain, (c) accessibility, and (d) location. 

CPSD’s proposal would also require CIPs to keep records of their inspections. 

Proposal 6D was submitted by SDG&E. SDG&E’s proposal is the same as 

CPSD’s proposal in all but two respects. First, CPSD’s proposal would require 

inspections of CIP-only poles within one span of a joint-use pole. SDG&E’s 

proposal would apply to CIP-only poles within three spans of a joint-use pole. 

Second, CPSD’s proposal would require detailed inspections every ten years for 

specified CIP facilities. SDG&E’s proposal would require detailed inspections 

every five years for CIP facilities located in high fire-threat areas of Southern 

California, and 10 years for other areas. 

The text of CPSD’s and SDG&E’s proposals would be placed in a new 

Rule 80.1A, with a reference to the new rule added to Rule 31.2. The text of the 

proposed revisions to Rule 31.2 and the new Rule 80.1A under CPSD’s and 

SDG&E’s proposals are shown in Appendix A of today’s decision. 

CPSD and SDG&E do not believe their proposals will result in significant 

additional costs for CIPs, as the CIPs are already required by Rule 31.2 to inspect 

their communication lines frequently and thoroughly. 

6.6.3. Position of the Parties 

The CIP-1 Proponents support both the CIP-1 proposal and the 

CIP-2 proposal. In contrast, the CIP-2 Proponents oppose the CIP-1 proposal but 

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support their own CIP-2 proposal. The CIP Coalition as a group is opposed to 

CPSD’s and SDG&E’s proposals.63 

The CIP Coalition asserts that it was the only party that provided a 

scientific basis for its proposals. In particular, AT&T retained Exponent Failure 

Analysis Associates (Exponent) to evaluate the fire risks associated with CIP 

facilities. Exponent analyzed all publicly available databases regarding fires 

associated with utility facilities, including databases maintained by Cal Fire.64 

Exponent also researched published technical literature and conducted an 

engineering review of failure modes that could cause fires. Exponent found that 

the fire risk associated with CIP facilities is negligible. The inspection cycles in 

the CIP-1 and CIP-2 proposals reflect the very low fire risk of CIP facilities. 

The CIP Coalition dismisses CPSD’s claim, summarized below, that it 

found several instances of CIP facilities that had not been properly maintained. 

The CIP Coalition rebutted CPSD allegation in Phase 1.65 Moreover, CPSD has 

not demonstrated that the alleged maintenance issues led to fires. 

The CIP Coalition urges the Commission to reject CPSD’s and SDG&E’s 

inspection proposals for the following reasons. First, both proposals require 

patrol inspections of specified CIP facilities throughout the state, regardless of 

the fire risk for a particular location. As a result, CPSD’s and SDG&E’s proposals 

 

63 Cox, a member of the CIP Coalition, does not take a position on Contested Proposals 

6A through 6D. 

64 The Exponent Report is attached in AT&T’s Phase 1 Opening Comments filed on 

March 27, 2009. 

65 CIP Coalition Phase 1 Opening Comments filed on March 27, 2009, at 10. 

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would waste resources on inspecting CIP facilities in areas where the risk of 

wildfires is low to nonexistent. 

Second, CPSD’s and SDG&E’s proposals would require patrol inspections 

every year in urban areas, and every two years in rural areas for most parts of 

the state. This defies common sense, according to the CIP Coalition. Rural areas 

are a greater fire risk than urban areas, yet CPSD’s and SDG&E’s proposals 

would require more frequent inspections in urban areas. 

Third, CPSD’s and SDG&E’s proposals would require more frequent 

inspections in the high fire-threat areas of rural Southern California compared to 

Northern California. The CIP Coalition sees no reason to provide less protection 

for Northern California. 

Fourth, CPSD’s and SDG&E’s proposals largely mirror the inspection 

requirements for electric utilities contained in GO 165. The CIP Coalition 

contends that it is unreasonable to subject CIP facilities to the same inspection 

requirements as power lines due to the vast difference in fire risks. Moreover, 

GO 165 is designed to address electric system reliability, not fire safety. 

Finally, the CIP Coalition states that SDG&E’s proposal is more onerous 

than CPSD’s proposal. SDG&E's proposal would (a) double the number of 

detailed inspections in the high fire-threat areas of Southern California, and 

(b) triple the number of CIP-only poles subject to inspections. The CIP Coalition 

alleges that SDG&E failed to provide any support for its onerous requirements. 

AT&T estimates its costs to implement CPSD’s and SDG&E’s proposals 

will be $18 million and $20 million per year, respectively. This estimate is 

exclusive of system development costs, equipment and tools to perform the 

inspections, and administrative costs. This cost estimate is only for AT&T and 

not other CIPs. The CIP Coalition declares that these costs are unreasonable 

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given the lack of evidence that CPSD’s and SDG&E’s proposals will decrease the 

already negligible fire hazards associated with CIP facilities. 

CMUA supports the CIP-1 proposal because it constitutes a significant 

improvement over the status quo and is a reasonable compromise of the various 

positions articulated by the parties. 

CPSD states that the intent of its proposal (Contested Proposal 6C) is to 

provide clear guidance regarding how frequently and thoroughly the CIPs must 

inspect all of their aerial facilities, not just facilities in high fire-threat areas. 

CPSD supports both its own proposal and SDG&E’s proposal, but prefers its 

own proposal over SDG&E’s proposal. CPSD opposes both CIP proposals. 

CPSD identified several ways that improperly maintained CIP facilities 

could cause nearby power lines to ignite fires. These are not hypothetical 

scenarios, according to CPSD, as its safety audits have discovered improperly 

maintained CIP facilities on many occasions. Moreover, CIP facilities in close 

proximity to power lines are dangerous regardless of location. Thus, in order to 

protect public safety, CIP inspection requirements must be statewide as in 

CPSD’s proposal, and not limited to high fire-threat areas as in the CIP-1 and 

CIP-2 proposals. 

CPSD raises two additional concerns with the CIP-2 proposal. First, it 

would require patrol inspections on a five-year cycle, which would allow 

violations to exist for several years before being inspected and corrected. 

Second, the CIP-2 proposal does not require detailed inspections. CPSD states 

that patrol inspections are intended to detect obvious safety hazards, while 

detailed inspections are intended to detect less obvious hazards. The lack of 

detailed inspections could result in safety hazards going undetected. 

DRA states without elaboration that it supports CPSD’s proposal. 

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IBEW 1245 supports CPSD’s and SDG&E’s proposals. IBEW 1245 believes 

that statewide inspections are needed due to the proliferation of CIP facilities on 

joint-use poles in recent years, from ground level to pole top. 

IBEW 1245 states that keeping climbing space clear of obstructions is vital 

for fire protection. This is because obstructions can hinder the ability of electric 

utility personnel to quickly and safely operate high voltage air switches, fuse 

assemblies, reclosers, and other protective devices. IBEW 1245 adds that patrol 

inspections usually do not detect climbing space violations. The only sure way 

to detect climbing space violations is with detailed inspections. 

IBEW 1245 disputes the CIP Coalition’s assertion that CIP facilities do not 

pose a significant fire risk. IBEW 1245 responds that it is not unusual for 

CIP facilities on joint-use poles to be in violation of the climbing space provisions 

of GO 95. IBEW 1245 further notes that CIPs have only recently been allowed to 

install pole-top antennas above high-voltage power lines. It is too soon to know 

what impact these installations will have on joint-use poles during high winds. 

IBEW 1245 believes that the continuing installation of antennas and the 

associated hardware through and above the high-voltage area of joint-use poles 

justifies an aggressive inspection regimen for CIP facilities. 

LA County states that CPSD’s and SDG&E’s proposals are necessary to 

mitigate the safety hazard posed by CIP facilities in close proximity to power 

lines. For example, CIP facilities can (1) add weight to existing poles, which 

increases the chance that a pole might break; (2) create additional conductor sag, 

which increases the risk of contact between power lines and communication 

lines; and (3) intrude into climbing space. In addition, many pole-top antennas 

have been installed in recent years, which has increased the potential for CIP 

facilities falling onto power lines. 

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LA County opposes the CIP-1 and CIP-2 proposals. LA County states that 

performing patrol inspections every three years under the CIP-1 proposal, or 

every five years under the CIP-2 proposal, is not frequent enough in areas where 

trees can grow rapidly in years with above average rainfall and strong Santa Ana 

winds blow each year. Another problem with the CIP-2 proposal is that it does 

not require detailed inspections. LA County notes that patrol inspections may be 

completed from a passing vehicle. Using this inspection regimen, many CIPs 

would only learn that a pole needs to be replaced when it fails. 

PacifiCorp supports CPSD’s and SDG&E’s proposals because they include 

reasonable inspection cycles on a statewide basis. PacifiCorp agrees with 

SDG&E’s position that inspection requirements should apply to CIP facilities 

within three spans of joint-use poles because of the possibility that damage to 

CIP facilities could cascade to nearby joint-use poles. 

PacifiCorp opposes the CIP-1 and CIP-2 proposals for several reasons. 

First, the proposals are limited to high fire-threat areas, but CIP facilities pose a 

fire hazard regardless of location. Second, the CIP-2 proposal does not require 

detailed inspections, which are needed to ensure that CIP facilities do not 

become a fire hazard. Finally, the CIP-2 proposal calls for patrol inspections 

every five years, which is not sufficient to protect against potential fire risks. 

PG&E supports the CIP-1 proposal, opposes the CIP-2 proposal, and is 

neutral with respect to CPSD’s and SDG&E’s proposals. PG&E sees the CIP-1 

proposal as providing reasonable inspection requirements that are focused on 

fire mitigation. PG&E opposes the CIP-2 proposal because it would only require 

patrol inspections of CIP facilities every five years, with no requirement for 

detailed inspections. This will do little to reduce fire risks, according to PG&E. 

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PG&E urges the Commission to require CIP facilities to be inspected using 

both routine patrols and detailed inspections. PG&E has seen enough problems 

with CIP facilities to believe that such an inspection program is warranted. On 

the other hand, PG&E recognizes that CIP facilities are less risky than electric 

facilities. Consequently, the intervals for CIP inspections do not need to match 

the inspection intervals used for electric facilities. 

PG&E disagrees with the Exponent Report that CIP facilities pose a 

negligible fire hazard. PG&E states that there have been more then 50 incidents 

during the past 3 years where PG&E found vegetation entangled with CIP 

facilities on joint-use poles. This entanglement affected adjacent power lines and 

caused both outages (which always have the potential for a fire) and three fires. 

PG&E recommends that if either CPSD’s proposal or SDG&E’s proposal is 

adopted, it should be limited to Southern California. PG&E also recommends 

that CIP inspection requirements be placed in a new Rule 80.1A as proposed by 

CPSD and SDG&E. 

SCE supports both CIP proposals and takes a neutral position on CPSD’s 

and SDG&E’s proposals. SCE believes it is important to require regular 

inspections of CIP facilities located near power lines in high fire-threat areas. 

SCE considers both CIP proposals to be aligned with this goal. In contrast, the 

CPSD and SDG&E proposals would expand the scope of inspections to locations 

outside of high fire-threat areas without adequate justification. 

SDG&E supports both its own proposal (Contested Proposal 6D) and 

CPSD’s proposal (Contested Proposal 6C), but SDG&E prefers its own proposal 

over CPSD’s proposal. SDG&E opposes both CIP proposals. 

SDG&E’s proposal differs from CPSD’s proposal in two respects. First, 

SDG&E’s proposal would require inspection of CIP facilities within three spans 

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of joint-use poles, versus one span under CPSD’s proposal. SDG&E submits that 

a three-span requirement is necessary because of the possibility that damage to 

CIP facilities could cascade to joint-use poles several spans away. Second, 

SDG&E’s proposal would require detailed inspections every five years in the 

high fire-threat areas of Southern California, versus every 10 years under CPSD’s 

proposal. SDG&E argues that 10 years is too long of an interval for detailed 

inspections in high fire-threat areas. The Commission has already established a 

five-year cycle for detailed inspections of electric facilities. SDG&E submits that 

it is reasonable for CIPs to have the same inspection cycle as electric utilities in 

high fire-threat areas. 

SDG&E disagrees with the CIP Coalition’s claim that SDG&E has not 

provided support for its proposal. During the workshop process, SDG&E 

presented photographs of broken and damaged CIP lashing wires that SDG&E 

had found during inspections of its facilities in 2010. 

SDG&E opposes the CIP-1 and CIP-2 proposals because their inspection 

cycles are too long. The CIP-1 proposal and CIP-2 proposal would require patrol 

inspections every three years and five years, respectively. SDG&E believes this 

is not frequent enough in high fire-threat areas where strong Santa Ana winds 

occur regularly. A five-year patrol inspection cycle is especially inappropriate, 

as it could allow hazards to exist for several years before being discovered. 

Detailed inspections should also occur more frequently than every nine years 

under the CIP-1 proposal, and not at all under the CIP-2 proposal. SDG&E 

conducts patrol inspections annually in high fire-threat areas and detailed 

inspections every five years. CIPs should do the same. 

Another flaw with the CIP proposals, according to SDG&E, is their lack of 

required inspection cycles for CIP facilities located outside of high fire-threat 

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areas. SDG&E states that because strong Santa Ana winds occur throughout its 

service territory, public safety requires regular inspections of CIP facilities that 

are located near power lines, regardless of location. 

SDG&E questions the finding in the Exponent Report that the fire risk 

associated with CIP facilities is negligible. Exponent based its finding, in part, on 

a review of historical fires in databases maintained by the National Fire Incident 

Reporting System and Cal Fire. It is SDG&E’s understanding that these 

databases do not track power-line fires that were caused, at least in part, by 

CIP facilities. For example, SDG&E does not believe the Cal Fire database shows 

that CIP facilities contributed to the ignition of the Guejito Fire in October 2007, 

even though Cal Fire determined that CIP facilities were involved. 

6.6.4. Discussion 

The issue before us is the scope of the CIP inspection requirement and 

associated record keeping. In deciding this issue, our principle concern is the 

prevention of catastrophic wildfires caused by improperly installed or 

maintained CIP facilities in close proximity to overhead power lines. We are also 

mindful that any adopted inspection requirement should achieve our goal of fire 

prevention in a cost-effective manner. 

The record of this proceeding establishes that CIP facilities located in close 

proximity to power lines are a latent fire hazard. CIP facilities include bare metal 

components such as messenger wires, lashing wires, and pole-top antennas. If 

not installed and maintained properly, CIP facilities could contact power lines 

and ignite a fire. CIP-only poles can also fail, causing a cascade that topples 

nearby joint-use poles with power lines attached, resulting in wildfires. 

The record of this proceeding also indicates that the occurrence of 

improperly installed and maintained CIP facilities is not a rare phenomenon. 

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Several parties who are in regular contact with CIP facilities – including CPSD, 

IBEW 1245, PacifiCorp, PG&E, and SDG&E – represent that they have found 

instances of improperly installed and/or maintained CIP facilities.66 

The potential fire hazard posed by CIP facilities in close proximity to 

power lines is illustrated by the 2007 wildfires. Cal Fire determined that one of 

these fires - the Guejito Fire - started when an electric power line and a CIP 

lashing wire securing a fiber optic cable came into contact with each other due to 

strong winds.67 Cal Fire did not attempt to determine the size of the Guejito Fire 

because it eventually merged with the larger Witch Fire that had started the day 

before. The Guejito Fire was unquestionable large, however. Within 30 minutes 

of being reported, the Guejito Fire reached I-15, closing the highway and 

 

66 Phase 2 Workshop Report, Appendix B, at B-73; CPSD Phase 2 Opening Brief at 16; 

CPSD Reply Brief at 8, Footnote 1; IBEW 1245 Opening Brief at 9 – 10; IBEW 1245 

Reply Brief at 2; PacifiCorp Reply Brief at 4; PG&E Reply Brief at 8; SDG&E Opening 

Brief at 16; and SDG&E Reply Brief at 14 – 15. 

67 Cal Fire Report, Fire Cause Determination, at 18. 

(http://www.fire.ca.gov/fire_protection/downloads/redsheet/CA-MVU010484_Complete.pdf.) We take official notice of Cal Fire’s report on our own 

motion pursuant to Pub. Util. Code §§ 701 and 1701, and Rule 13.9 of the 

Commission’s Rules of Practice and Procedure. Cal Fire did not reach a conclusion 

about the root cause of the contact between a power line and a CIP lashing wire that 

gave rise to Guejito Fire. Today’s decision cites Cal Fire’s report for the limited 

purpose of noting that Cal Fire’s initial investigation attributed the potential cause of 

the Guejito Fire to contact between a power line and a CIP lashing wire. Consistent 

with the Phase 2 Scoping Memo at 2, today’s decision does not (i) decide any issues 

that were litigated in the Commission’s investigation of the Guejito Fire, which is 

now closed (D.10-04-047, Ordering Paragraph 9); (ii) determine the root cause of the 

Guejito Fire; or (iii) find that the Guejito Fire was caused by improperly installed or 

maintained facilities. 

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disrupting the evacuation of communities threatened by the Witch Fire. The 

Guejito Fire then crossed I-15 and spread several miles to the west.68 

In light of the inherent fire risk of CIP facilities located in close proximity 

to power lines, it is essential that CIP facilities be installed and maintained 

properly to protect public safety. To achieve this goal, we conclude that CIPs 

should be required to perform patrol and detailed inspections on the following 

cycles: 

• Patrol inspections every year for CIP facilities located in high 

fire-threat areas of Southern California. 

• Patrol inspections every two years for CIP facilities located in 

high fire-threat areas of Northern California. 

• Detailed inspections every five years for CIP facilities located in 

high fire-threat areas of Southern California. 

• Detailed inspections every 10 years for CIP facilities located in 

high fire-threat areas of Northern California. 

These inspection requirements shall apply to CIP facilities attached to 

joint-use poles and to CIP-only poles within three spans of a joint-use pole. 

Today’s decision defines Southern California as Imperial, Los Angeles, Orange, 

Riverside, Santa Barbara, San Bernardino, San Diego, and Ventura Counties. 

Northern California is defined as all other counties. High fire-threat areas are 

shown on the fire-threat maps adopted later in today’s decision. 

We conclude that the protection of public safety requires patrol inspections 

every year, and detailed inspections every five years, for CIP facilities located in 

the high fire-threat areas of Southern California. The catastrophic wildfires of 

 

68 California Fire Siege 2007 – an Overview, at 84. 

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October 2007 convince us that extra precautions are warranted in these areas. In 

addition, the strong Santa Ana winds that occur regularly in these areas 

substantially increase the risk that improperly installed or maintained facilities 

will ignite a fire. Frequent inspections will help to mitigate this risk. 

We also conclude that patrol inspections every two years, and detailed 

inspections every ten years, is sufficient for CIP facilities located in the high 

fire-threat areas of Northern California. There is no history of catastrophic 

power-line fires in Northern California, and Northern California does not 

experience Santa Ana winds that contribute significantly to the risk of 

catastrophic power-line fires in Southern California. Therefore, because the 

overall risk of power-line fires is lower in Northern California, we can safely 

reduce the frequency (and associated cost) of inspections. 

We agree with SDG&E that the adopted inspection requirements in high 

fire-threat areas should apply to CIP-only poles located within three spans of a 

joint-use pole. It is widely recognized in the utility industry that the failure of 

one pole, or the facilities attached to a pole, can cascade to nearby poles. 

Limiting CIP inspections to one-span from joint-use poles would not provide an 

adequate buffer to protect against cascading failures. 

To ensure consistent implementation of the adopted inspection intervals, 

and to provide flexibility, we define the term “year” as 12 consecutive calendar 

months starting the first full calendar month after an inspection is performed, 

plus or minus two calendar months, not to exceed the end of the calendar year 

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the next inspection is due.69 For example, if an inspection is performed in 

June 2012 and the required inspection interval is two years, the next inspection 

must be completed during the period of April 1 - August 31, 2014.70 However, if 

the inspection is performed in December 2012, the next inspection must be 

completed during the period of October 1 – December 31, 2014. We will also 

add this definition of “year” to GO 165 to ensure consistent implementation of 

patrol and detailed inspection intervals for both CIPs and electric utilities.71 

We decline to adopt the CIP-1 and CIP-2 proposals for patrol inspection 

cycles of three years and five years, respectively, in high fire-threat areas. As 

LA County points out, vegetation can grow rapidly in years when rainfall is 

above average. A three-year or five-year inspection cycle could allow 

vegetation-related fire hazards to exist for several years before being discovered 

and remedied. 

We also decline to adopt the CIP-2 proposal to rely exclusively on patrol 

inspections, with no requirement for detailed inspections, in high fire-threat 

areas. While patrol inspections can detect obvious fire hazards, some hazards 

can only be detected by detailed inspections that require an inspector to examine 

each utility pole carefully. Consequently, relying exclusively on patrol 

 

69 The definition of “year” adopted by today’s decision applies only to patrol and 

detailed inspection intervals, and not to intrusive inspection intervals. 

70 Likewise, if an inspection interval is five years, the next inspection must be 

completed within 60 calendar months, plus or minus two calendar months, not to 

exceed the end of the calendar year in which the next inspection is due. 

71 The definition of “year” adopted by today’s decision for patrol and detailed 

inspection intervals is consistent with the definition of “year” in D.04-04-065 at 29 

where the Commission indicated that a year should be defined in a way that 

provides companies a “limited degree of flexibility in scheduling” inspections. 

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inspections could allow dangerous fire hazards to go undetected until disaster 

strikes. This is an unacceptable risk in the wake of the catastrophic wildfires of 

October 2007. 

The CIPs argue that the adopted inspection cycles for CIP facilities in high 

fire-threat areas are improperly modeled on the GO 165 inspection rules for 

electric utilities. The CIPs assert that GO 165 is intended to promote reliable 

service, not reduce fire risk. This description of GO 165 is incorrect. A primary 

purpose of GO 165 is to ensure safe electrical service.72 The prevention of fires is 

an integral part of this safety mandate. 

We are not persuaded by the CIP Coalition that the Exponent Report 

demonstrates that CIP facilities pose so little fire risk that the inspection 

requirements adopted by today’s decision are excessive. The Exponent Report 

relied, in part, on databases of historical fires that do not appear to track powerline fires that may have been caused, at least in part, by CIP facilities.73 

The CIP Coalition argues that CPSD’s and SDG&E’s proposals would be 

unduly costly to implement. For example, AT&T estimates that it would cost 

$18 million to implement CPSD’s proposal and $20 million to implement 

SDG&E’s proposal. As a preliminary matter, the CIP inspection requirements 

adopted by today’s decision should cost considerably less than estimated by 

AT&T because the geographic scope of the adopted requirements is significantly 

less than proposed by CPSD and SDG&E.74 Moreover, because CIPs are already 

 

72 GO 165, Sections I, II, III.F, and IV. 

73 SDG&E Reply Brief at 10 - 11. 

74 CPSD’s and SDG&E’s proposed mandatory inspection cycles would apply to the 

entire state. The adopted inspection cycles apply only to high fire-threat areas. 

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required by Rule 31.2 to inspect their facilities frequently and thoroughly, there 

should not be significant additional costs to implement the inspection 

requirements adopted by today’s decision. In our judgment, the costs incurred 

by CIPs will be more than offset by the public-safety benefits from the reduced 

risk of catastrophic wildfires. 

We agree with CPSD and SDG&E that the CIPs should inspect their aerial 

facilities throughout the state as a fire-prevention measure, but we decline to 

adopt CPSD’s and SDG&E’s proposals to require both patrol and detailed 

inspections for all lower-risk CIP facilities and to set mandatory inspection cycles 

for all lower-risk CIP facilities.75 The central focus of this proceeding is the 

reduction of fire hazards posed by overhead electric utility and CIP facilities. 

CPSD and SDG&E have not demonstrated that requiring both patrol and 

detailed inspections, and requiring inspections on a prescribed cycle, for all 

lower-risk CIP facilities will provide a meaningful or cost-effective reduction in 

the fire hazard posed by CIP facilities, particularly in light of the much lower fire 

risk associated with aerial CIP facilities compared to overhead power lines.76 

 

75 Today’s decision defines a lower-risk CIP facility as an aerial CIP facility that is not 

attached to (i) a joint-use pole in a high fire-threat area, or (ii) a CIP-only pole within 

three spans of a joint-use pole in a high fire-threat area. 

76 The patrol inspection intervals for all aerial CIP facilities proposed by CPSD and 

SDG&E are identical to the mandatory patrol inspection intervals for power lines in 

GO 165. We agree with the observation by the CIP Coalition in its comments on the 

proposed decision at page 8 that “[w]hile electric power lines are uninsulated, 

electrified (14kV to 69kV), mounted near the top of wood poles, and capable of 

being a source of ignition, CIP facilities are insulated, have low voltage, and are 

mounted many (typically six) feet below electric power lines. As over 100 years of 

experience confirms, electric facilities are inherently more risky.” 

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We recognize that the fire hazard associated with aerial CIP facilities can 

vary widely depending on the location of the facilities and other factors. For 

example, CIP facilities attached to a joint-use pole in an area of dense vegetation 

are typically a greater potential fire hazard than CIP facilities attached to a 

joint-use pole in an area of coastal sand dunes. Therefore, in order to protect 

public safety while taking into account the much lower but widely varying levels 

of fire hazards, we will require CIPs to conduct patrol or detailed inspections in 

all areas of the state, with the type of inspection and the inspection intervals for 

lower-risk CIP facilities to be determined by the CIPs themselves based on 

factors that reflect the site-specific safety hazard for each location.77 

The CIP inspection requirements adopted by today’s decision are 

minimum requirements. CIPs should inspect their facilities in high fire-threat 

areas more often then required by today’s decision if doing so is necessary to 

protect public safety. We emphasize that although today’s decision does not 

adopt mandatory inspection cycles for CIP facilities in lower risk areas, this does 

not affect the CIPs’ duty under Rule 31.2 to inspect their facilities in all areas of 

the state frequently and thoroughly. Nor does today’s decision relieve CIPs of 

their obligation under Pub. Util. Code § 451 to maintain all of their facilities in a 

safe condition at all times. 

We also note that the definition of “high fire-threat areas” adopted by 

today’s decision includes areas that are designated as “Extreme” and “Very 

High” fire threat zones on the FRAP Map, but excludes areas that are designated 

 

77 Today’s decision requires the type, frequency, and thoroughness of inspections of 

lower-risk aerial CIP facilities to be based on the following factors: (a) Proximity to 

electric facilities, (b) terrain, (c) accessibility, (d) location, and (e) fire risk. 

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as “High” fire-threat zones on the FRAP Map.78 We expect the CIPs to conduct 

more frequent and thorough inspections in the “High” fire-threat zones on the 

FRAP Map than in the lower risk fire-threat zones on the FRAP Map.79 

CIPs shall keep records that provide the following information for each 

facility: The location of the facility, the date(s) the facility was inspected, the 

results of each inspection, the personnel who performed each inspection, the date 

and description of each corrective action, and the personnel who performed each 

corrective action. 

Consistent with CPSD’s and SDG&E’s proposals, the adopted inspection 

and record-keeping requirements shall be placed in a new Rule 80.1(A) of GO 95, 

with a reference to the new rule added to Rule 31.2. The adopted text is 

contained in Appendix B of today’s decision. 

6.7. Contested Proposal 6E re: GO 95, Rule 80.1B 

6.7.1. Summary of Proposal 

GO 165 requires intrusive inspections of wood poles that support power 

lines. GO 165 defines intrusive inspections as “the movement of soil, taking 

samples for analysis, and/or using more sophisticated diagnostic tools beyond 

visual inspections or instrument reading.” The first intrusive inspection of a pole 

must occur during years 15 through 24 of a pole’s service life. Poles that have 

passed an intrusive inspection do not need to be inspected for another 20 years. 

 

78 We will address in Phase 3 the question of whether, and to what extent, those areas 

that are designated as “High” fire-threat zones on the FRAP Map should be 

included in the definition of “high fire-threat areas” adopted by today’s decision. 

79 The lower risk fire-threat zones are designated on the FRAP Map as “Moderate, 

Non-fuel, and Not Mapped.” 

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There is currently no requirement for intrusive inspections of wood poles 

that support only CIP facilities (“CIP-only poles”). CPSD proposes to add a new 

Rule 80.1B to GO 95 that would apply the GO 165 intrusive inspection 

requirements to CIP-only poles that are physically connected to joint-use poles. 

CPSD’s proposal would be limited to CIP-only poles that are (1) interset or 

within three spans of a joint-use pole in the high fire-threat areas of Southern 

California, and (2) within one span of a joint-use pole in all other areas. The text 

of CPSD’s proposed Rule 80.1B is contained in Appendix A of today’s decision. 

CPSD estimates that the cost for intrusive inspections of CIP-only poles 

would be approximately $30 - $50 per pole. However, CPSD did not provide an 

estimate of the total cost of its proposal. 

6.7.2. Position of the Parties 

CPSD states that the failure of a CIP-only pole that is physically connected 

to joint-use poles could damage power-line facilities and thereby ignite a fire. 

The failure of CIP-only poles could also cause other public-safety issues such as 

the loss of 911 service. CPSD’s proposal to require intrusive inspections is 

intended to ensure that CIP-only poles are repaired or replaced prior to failure. 

CPSD believes that intrusive inspections are warranted by the fact that 

GO 95 allows CIP-only poles to have a lower safety factor than poles that 

support power lines, and thus can break more easily in high winds. The fact that 

CIP-only poles are not as sturdy also means that it is easier for the failure of one 

CIP-only pole to cascade down a line of CIP-only poles during high winds. 

CPSD observes that high-wind conditions which can cause CIP-only poles 

to break are the same conditions that can lead to catastrophic fires. Because the 

risk of wind-related fires is much higher in Southern California, CPSD’s proposal 

would require intrusive inspections of CIP-only poles within three spans of 

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joint-use poles in the high fire-threat areas of Southern California, versus one 

span in all other areas of California. 

CPSD’s estimated cost of intrusive inspections of $30 - $50 per pole is 

based on information provided at the workshops from several parties. Osmose 

Utility (which performs intrusive inspections) stated that the cost for intrusive 

inspections, including full excavation and pole treatment, is $30 to $50 per pole. 

PG&E estimated its costs at $45 per pole. PacifiCorp estimated its costs at $39 

per pole. CPSD also believes that its proposal could save money over the long 

run. According to Osmose Utility, wood poles will last approximately 45 years 

with no inspection or treatment, but will last 80 years with 2 to 3 treatments. 

CPSD’s proposal is supported by DRA, IBEW 1245, LA County, 

PacifiCorp, PG&E, SCE, SDG&E, Sierra Pacific, and TURN. They agree that the 

failure of a CIP-only pole could damage nearby joint-use poles and ignite a fire. 

Therefore, as a matter of public safety, CIP-only poles need to be inspected. 

LA County adds that CIP-only poles that fail during high-wind events can not 

only ignite fires, but also block egress and ingress of both evacuees and first 

responders, turning a hazardous situation into a life-threatening one. 

While PG&E supports intrusive inspections for CIP-only poles, PG&E 

states that CIP-only poles are less of a fire risk than joint-use poles. 

Consequently, the intervals for a CIP inspection program do not need to match 

the inspection intervals for electric facilities. 

SCE does not take a position on whether every element of CPSD’s 

proposal is necessary or cost effective. In general, SCE would prefer to limit 

intrusive inspections for CIP-only wood poles to high fire-threat areas. 

SDG&E asserts there is a clear need for intrusive inspections of CIP-only 

poles. SDG&E has encountered problems with the failure of CIP-only poles, 

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including a March 2010 failure of a CIP-only pole that cascaded into SDG&E’s 

power-line facilities and ignited a small fire. 

CPSD’s proposal is opposed by the CIP Coalition.80 The CIP Coalition 

argues that CPSD’s proposal is outside the scope of this proceeding as set forth 

in the Phase 2 Scoping Ruling: 

The purpose of this rulemaking proceeding is to consider 

measures to reduce fire hazards associated with: (1) electric 

transmission and distribution facilities and (2) communication 

infrastructure provider (CIP) facilities in close proximity to 

overhead electric power lines. (Phase 2 Scoping Ruling at 1.) 

The CIP Coalition contends that CPSD’s proposal does not focus on fire 

hazards associated with CIP facilities in close proximity to power lines because 

(1) the proposal is not limited to high fire-threat areas, and (2) there are no power 

lines attached to CIP-only poles, and hence no power lines in close proximity. 

The CIP Coalition asserts there is no evidence that CIP-only poles have 

caused fires or that intrusive testing of CIP-only poles will reduce fires. While 

several parities speculate that intrusive testing could identify poles that are likely 

to fail and cause a fire, speculation should not be the basis for a new regulation. 

The CIP Coalition dismisses LA County’s concern that CIP-only poles can 

fall and block egress and ingress during emergencies, since LA County failed to 

cite one incident where a CIP pole has blocked access. The CIP Coalition also 

dismisses SDG&E allegation that a CIP-only pole broke in March 2010 and fell 

onto SDG&E’s power-lines, causing a small fire. SDG&E did not provide 

evidence that the incident actually occurred or that intrusive inspections could 

 

80 Cox, a member of the CIP Coalition, does not take a position on CPSD’s proposal. 

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have prevented the incident. Regardless, one incident is not a sufficient basis for 

adopting a new statewide regulation. 

The CIP Coalition asserts that the costs of intrusive inspections will be 

significant. For AT&T alone, the estimated costs to test all of its CIP-only poles 

would be approximately $11 million.81 Given that there would be no reduction 

in fire risks, these costs should not be imposed on the CIPs and their customers. 

If the Commission adopts an intrusive inspection requirement for CIPonly poles, the CIP Coalition submits that the inspection cycles in GO 165 for 

electric facilities are excessive for CIP facilities given the difference in fire risks. 

6.7.3. Discussion 

The issue before us is the whether to adopt CPSD’s proposal to require 

intrusive inspections of CIP-only poles. In deciding this issue, our main concern 

is the prevention of wildfires caused by poorly maintained CIP-only poles in 

close proximity to power lines. Any adopted inspection requirement should 

achieve our goal of fire prevention in a cost-effective manner. 

All wood poles will fail at some point. If not maintained properly and 

replaced when necessary, CIP-only poles can break and damage nearby joint-use 

poles and the attached power lines, resulting in a fire. Intrusive inspections can 

determine the remaining strength of wood poles so that poles can be treated or 

replaced before they fail. 

In order to protect public safety, we conclude that it is reasonable to set 

intrusive inspection cycles for CIP-only poles connected to nearby power lines. 

 

81 AT&T’s estimate is for all of its CIP-only poles, not just those poles that would be 

affected by CPSD’s proposal. AT&T does not know at this time how many of its 

CIP-only poles would be subject to CPSD’s proposal. 

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Accordingly, we will adopt CPSD’s proposal with one significant modification. 

While CPSD’s proposal would apply statewide, we agree with the CIP Coalition 

and SCE that mandatory intrusive inspection cycles for CIP-only poles should be 

limited to high fire-threat areas. Consistent with CPSD’s proposal, we will 

require intrusive inspections of CIP-only poles located within one span of 

joint-use poles in the high fire-threat areas of Northern California, and within 

three spans of joint-use poles in the high fire-threat areas of Southern California. 

The adopted intrusive inspection cycles shall be placed in a new Rule 80.1B of 

GO 95 as proposed by CPSD. The text of the new Rule 80.1B is contained in 

Appendix B of today’s decision.82 

The intrusive inspection requirements adopted by today’s decision are 

minimum requirements. CIPs should inspect all of their poles as often as 

necessary to protect public safety. 

CPSD did not propose a record keeping requirement for intrusive 

inspections. We believe that such a requirement is necessary to monitor 

compliance. Therefore, we will require CIPs to keep records that provide the 

following information for each CIP-only pole: The location of the pole, the 

date(s) the pole was inspected, the results of each intrusive inspection, the 

personnel who performed each inspection, the date and description of any 

corrective actions, and the personnel who performed the correction actions. 

We find no merit to the CIP Coalition’s argument that the issue of 

intrusive inspections for CIP-only poles is outside the scope of this proceeding 

 

82 The adopted text for Rule 80.1B includes references to the fire-threat maps that are 

adopted later in today’s decision. 

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because these poles do not pose any fire risk. GO 95 allows wood poles that 

support CIP facilities to have a lower safety factor than poles that support power 

lines. Therefore, CIP-only poles can break more easily when subjected to high 

winds, falling vegetation, or other stresses. The failure of a CIP-only pole that is 

physically connected to a nearby joint-use pole by a messenger wire, guy wire, or 

other means can pull down the connected joint-use pole and attached power 

lines, resulting in a fire. High wind conditions that can cause CIP-only poles to 

break are the same conditions that can lead to a catastrophic wildfire, especially 

in Southern California which experiences Santa Ana winds regularly. 

We are not persuaded by the CIP Coalition that there is no evidence that 

CIP-only poles pose a fire hazard. It is indisputable that wood poles can fail if 

they are not maintained properly and replaced when necessary. By requiring 

intrusive inspections of CIP-only poles, today’s decision will help ensure that 

poles in need of repair or replacement are detected so they do not damage 

nearby electric facilities and thereby cause a fire. 

Finally, we disagree with the CIP Coalition that the cost of intrusive 

inspections exceeds the benefits. The cost of intrusive inspections should be far 

less that AT&T’s estimate of $11 million to test all of its CIP-only poles. Today’s 

decision sets intrusive inspection cycles for only a fraction of AT&T’s poles and 

allows CIPs to spread the cost of intrusive inspections over many years. Once a 

wood pole has passed an intrusive inspection, it would only be required to be 

intrusively inspected on a 20-year cycle thereafter. As result, the annual costs 

incurred by CIPs to implement the intrusive inspection requirements adopted by 

today’s decision should be relatively small, and in the case of AT&T, 

significantly less than $11 million. We believe the costs will be more than offset 

by the public-safety benefits from the reduced risk of catastrophic wildfires. 

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6.8. Contested Proposal 7A re: GO 95, Rule 35, Paragraph 4 

6.8.1. Summary of Proposal 

In the Phase 1 Decision, the Commission indicted that it would consider 

proposals in Phase 2 for dealing with landowners who obstruct vegetation 

management.83 In response, PG&E, SCE, and SDG&E (together, “the Joint 

Utilities”) propose to add a new Paragraph 4 to Rule 35 of GO 95 that would 

allow electric utilities to shut off power to customers who obstruct vegetation 

management on their property. The proposal would apply to all of a customer’s 

service locations, not just the location where the customer obstructs vegetation 

management. For example, if a farmer refuses to allow access to a transmission 

line in a cultivated field, the electric utility could shut off power to the farmer’s 

residence, vacation home, and any other properties owned by the farmer in the 

utility’s service territory. Electric utilities would provide written notice at least 

five days before shutting off service, unless the vegetation condition poses an 

imminent safety hazard. Importantly, this proposal does not contemplate 

shutting off service to state or city customers. The text of the proposed addition 

to Rule 35 is contained in Appendix A of today’s decision. 

The Joint Utilities will incur little or no net costs to implement the 

proposal. The cost to reconnect service will be at the customer’s expense. 

6.8.2. Position of the Parties 

The Joint Utilities’ proposal is supported by CMUA, IBEW 1245, 

PacifiCorp, Sierra Pacific, and TURN. The proponents state the proposal is 

aimed at the small number of property owners who refuse to allow electric 

 

83 D.09-08-029 at 29-30. 

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utilities to access their property to keep power lines clear of vegetation. These 

property owners place their communities in jeopardy of potential fires, power 

outages, and injury to power-line workers and the public. 

The Joint Utilities, together with PacifiCorp and Sierra Pacific (collectively, 

“the electric investor-owned utilities” or “electric IOUs”) already have authority 

under their tariffs to terminate service if a customer does not permit vegetation 

management activities. They see the proposed rule as a logical extension of their 

existing authority. The electric IOUs also represent that they will (1) shut off 

power only as a last resort, and (2) attempt to contact the customer multiple 

times to resolve a vegetation-management dispute before shutting off power. 

The electric IOUs expect the threat of shutting off power will convince customers 

to allow vegetation management. 

Although TURN supports the Joint Utilities’ proposal, TURN also 

recommends that the electric IOUs make the following modifications to their 

tariffs. First, electric Tariff Rule 11 (Discontinuance of Service) should be revised 

to state that the utility may terminate service at any location where the customer 

receives service whenever a customer obstructs access to overhead facilities, such 

that the electric utility cannot inspect its facilities or there is an imminent threat 

that required vegetation clearances will not be maintained. 

Second, the tariffs should describe the notice requirements for 

vegetation-related shut-offs. TURN recommends that the Commission direct 

utilities to provide written notice 30 days prior to a vegetation-related 

disconnection. TURN states that 30 days’ notice will give the customer an 

opportunity to work with the utility to have trees cut in a manner agreeable to 

both parties, but still give electric utilities the leverage they assert is needed to 

complete vegetation management activities. 

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Third, TURN recommends that electric utilities attempt to contact, by 

telephone or in person, an adult person residing at the property where service 

will be terminated and at the billing address of the customer of record. TURN 

also recommends that the utilities attempt such contact at least 25 days prior to 

the termination of service; a second attempt at least five days prior to 

termination of service if no prior contact has been achieved with an adult person; 

and a final attempt at least 24 hours prior to termination of service. 

Fourth, because the Joint Utilities’ proposal may impact persons living in 

multi-residential buildings, TURN recommends that the electric IOUs be 

required to post a notice on each tenant’s door and in common areas that informs 

the tenants that service will be discontinued for obstruction of vegetation 

management activities at least 30 days prior to discontinuance of service. 

Fifth, TURN recommends that utility tariffs be modified to clarify that 

disconnections for vegetation management noncompliance will be subject to the 

same heightened notice requirements for sensitive customers as utilities apply to 

disconnections for non-payment. TURN also recommends that the Commission 

require the final attempt to contact a sensitive customer be an in-person visit. 

Finally, TURN recommends that any requirements regarding 

disconnection-related communications with customers who are not 

English-proficient, or who have vision or hearing impairments, also apply to 

vegetation management disconnections. 

The electric IOUs take different positions with respect to TURN’s tariff 

recommendations. PacifiCorp and Sierra Pacific support TURN’s 

recommendations. PG&E, SCE, and SDG&E do not object to modifying their 

tariffs to reflect their proposed revisions to Rule 35. However, they oppose 

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TURN’s other tariff recommendations because they would undermine the 

disconnection process by making it too unwieldy. 

The Joint Utilities’ proposal is opposed by CFBF, CPSD, LA County, and 

MGRA. In general, the opponents acknowledge that electric IOUs have 

authority under their tariffs to shut off power where there is an imminent safety 

hazard. The Joint Utilities’ proposal would go much further by allowing electric 

IOUs to shut off power at locations where no safety hazard exists. It would also 

create collateral harm by shutting off power to persons other than the customer 

who is obstructing vegetation management (e.g., residents of sub-metered 

apartments). 

CFBF argues that the Joint Utilities’ proposal is outside the scope of this 

proceeding because it is not focused on reducing fire hazards. Rather, the 

proposal would allow electric IOUs to shut off power anywhere, not just in high 

fire-threat areas. 

CFBF states there may be valid reasons for customers to balk at the timing 

or extent of vegetation management activities. The proposed rule unfairly 

provides the utility with carte blanche to shut off power when there is a 

legitimate dispute. Agricultural customers would be hardest hit by this 

proposal, as their properties are crossed by thousands of miles of power lines. 

CFBF further argues that the Commission has no authority to authorize 

utilities to shut off power as a device to force property owners to provide access 

to their properties. CFBF states that the terms and conditions of access are 

governed by easement agreements between property owners and utilities. The 

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Commission has acknowledged it does not have jurisdiction to adjudicate 

easement disputes and must defer to the courts.84 

MGRA asserts the electric IOUs are seeking police powers to force entry 

onto property. MGRA believes the Commission’s efforts would be better 

focused on finding ways to enhance law enforcement cooperation with utilities 

rather than placing the right of enforcement in the hands of utilities. 

If the Commission adopts the Joint Utilities’ proposal, CPSD recommends 

that the authority to shut off power should not be added to GO 95, which 

governs design, maintenance, and construction standards for overhead lines. 

Instead, it should be addressed in utilities’ tariffs as a “condition of service.” 

6.8.3. Discussion 

The issue before us is whether to adopt the Joint Utilities’ proposal to 

authorize electric utilities to shut off power to customers who obstruct vegetation 

management on their property. The proposal would allow electric utilities to 

terminate service at any location where a customer receives service, not just the 

location where the customer obstructs vegetation management. In deciding this 

issue, our main concern is the prevention of wildfires and outages caused by 

property owners who refuse to allow access to power-line facilities for vegetation 

management activities. We must also weigh the negative impacts of shutting off 

power to all service locations of a non-cooperative customer. 

The failure to keep power lines clear of vegetation is a serious threat to 

public safety and service reliability. It is well known that vegetation contact with 

high-voltage power lines can ignite fires and/or cause power outages that 

 

84 See, for example, D.98-04-070, 80 CPUC 2d 199, 200. 

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deprive communities of vital electric service. In addition, the task of maintaining 

clearances is much more dangerous when vegetation is allowed to grow close to 

power lines. 

We agree with the Joint Utilities that in order to protect public safety and 

maintain service reliability, electric utilities need appropriate tools to deal with 

customers who obstruct access to their property for vegetation-management 

activities. We find that the Joint Utilities’ proposal is a reasonable solution to 

address a known threat to public safety and welfare, and we adopt the proposal 

with the following conditions. First, consistent with the Joint Utilities’ proposal, 

an electric utility may shut off power to a property owner who obstructs access 

to the utility’s overhead power-line facilities located on the owner’s property, 

resulting in a breach of the minimum vegetation clearances required by GO 95, 

Rule 35, Table 1, Cases 13 and 14.85 We recognize that shutting off power to a 

customer is a harsh remedy, but public safety and welfare is placed at grave risk 

when there is a breach of the required minimum clearances. In our judgment, 

the remedy is commensurate with the circumstances. 

Second, as proposed by the Joint Utilities, the authority to shut off power 

to customers who obstruct vegetation management does not extend to state and 

local government customers. 

Third, we decline to adopt the Joint Utilities’ request for broad authority to 

terminate service at all locations where a customer receives service. This could 

cause harmful disruption to third parties who have no responsibility whatsoever 

 

85 The required minimum vegetation clearance varies with voltage. For a 300 kV 

transmission line, the required minimum radial clearance is 120 inches in the high 

fire-threat areas of Southern California and 75 inches in all other areas of the state. 

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for a customer’s obstruction of vegetation management. In order to keep the 

remedy of shutting off power focused on the customer responsible for 

obstructing vegetation management, we will limit the electric utilities’ authority 

to shut off power to one meter serving the property owner’s primary residence, 

or if the property owner is a business entity, the entity’s primary place of 

business. This one meter is in addition to shutting off power, if necessary for 

public safety, at the location of the vegetation hazard.86 

Fourth, prior to shutting of power, electric utilities shall follow the thencurrent procedures and notice requirements applicable to discontinuance of 

service for non-payment, including requirements applicable to medical baseline 

and life support customers, customers who are not proficient in English, and 

multifamily accommodations. To the extent practical, the required procedures 

and notice requirements should be completed prior to a breach of the minimum 

required vegetation clearances in Rule 35, Table 1, Cases 13 and 14, so that power 

may be shut off promptly if a breach occurs. 

Finally, for vegetation hazards that are an immediate threat to public 

safety (such as vegetation contacting a power line during windy conditions), 

electric utilities may shut off power to the obstructing property owner’s 

residence or primary place of business at any time without prior notice, unless 

the obstructing property owner is a medical baseline customer. If power is shut 

off without prior notice, the electric utility shall thereafter attempt to contact the 

property owner for five consecutive business days by daily visits to the property 

 

86 If the vegetation hazard involves a major distribution line or a transmission line, it 

might not be possible to shut off power at the location of the vegetation hazard 

without affecting many other customers. 

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owner’s residence or primary place of business, in addition to sending a written 

notice, to inform the property owner why power has been shut off and what 

steps need to be taken to restore service. If a utility determines that it is 

necessary to shut off power to a medical baseline customer, the utility shall 

attempt to notify the customer by telephone prior to the shut off. 

We agree with CPSD and TURN that the authority to shut off power to a 

customer who obstructs vegetation management should be added to the utilities’ 

tariffs as a “condition of service.” To this end, each electric IOU shall file and 

serve a Tier 3 advice letter to make the necessary revisions to its tariffs no later 

than 60 days from the issuance date of today’s decision. 

We further agree with CPSD that the electric utilities’ authority to shut off 

power should not be added to GO 95, which governs design, maintenance, and 

construction standards for overhead lines. This is consistent with the treatment 

of electric utilities’ existing authority contained in their tariffs, but not in GO 95, 

to shut off power at locations where there is a safety hazard.87 

CFBF argues that the Commission lacks jurisdiction to determine the 

rights of parties in real property disputes. Today’s decision does not attempt to 

resolve property disputes. Rather, today’s decision addresses the terms and 

conditions under which electric utilities may terminate service to a defined 

group of customers, which is matter that is clearly within the Commission’s 

jurisdiction. If an electric utility conducts vegetation management activities in a 

way that violates its easement agreement with a property owner, the property 

owner may pursue legal remedies through the courts. 

 

87 See, for example, PG&E Tariff Rules 11.H and 14. 

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In its comments on the proposed decision, CFBF argues that it is 

unreasonable for an electric utility to shut off service to a customer who obstructs 

vegetation management, since an electric utility’s service to its retail customers is 

unrelated to the utility’s vegetation management activities. We disagree. 

Electric utilities cannot serve their customers without transmission lines. Electric 

utilities are already authorized to discontinue service to a customer who refuses 

to allow a utility to access its service connection facilities on the customer’s 

property (e.g., a service drop and meter).88 By the same token, electric utilities 

should be authorized to discontinue service to a customer who prevents the 

utility from accessing the utility’s other facilities on the customer’s property that 

are used to provide service to the customer, either directly or indirectly. 

It is also important to keep in mind that electric utilities have a duty under 

GO 95 and Pub. Util. Code § 451 to keep their transmission lines clear of 

vegetation in order to provide reliable service and to protect public safety.89 We 

believe it is unreasonable to compel an electric utility to serve a customer who 

actively hinders the utility’s efforts to comply with the law, provide reliable 

service, and protect public safety. 

We agree with CFBF that farmers are heavily impacted by vegetation 

management activities, as farmlands are crisscrossed by thousands of miles of 

power lines. Although electric utilities have a duty to keep power lines clear of 

 

88 See, for example, PG&E’s and SDG&E’s Electric Tariff Rule 16.F.3. 

89 § 451 requires every public utility “to furnish and maintain such adequate, efficient, 

just, and reasonable service, instrumentalities, equipment, and facilities... as are 

necessary to promote the safety, health, comfort, and convenience of its patrons, 

employees, and the public.” 

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vegetation in order to maintain reliability and protect public safety, they should 

do so in a way that minimizes disruption to farming operations and damage to 

cultivated fields. When possible, electric utilities should schedule vegetation 

management at times mutually convenient to the utility and the farmer. In 

general, electric utilities should avoid scheduling vegetation management 

activities immediately after planting, during harvest, and after pesticide 

applications and when an intrusion onto cropland can be costly for the farmer 

and/or dangerous for the vegetation management crew. 

We recognize there may be instances where electric utilities conduct 

vegetation management activities in an inappropriate manner. Any landowner 

who believes an electric utility is conducting vegetation management activities in 

a way that violates today’s decision or another Commission decision, order, or 

rule may file a complaint pursuant to Rule 4.1 of the Commission’s Rules of 

Practice of Procedure. Upon a showing of good cause, the Commission may 

grant temporary injunctive relief that prohibits the alleged violation from 

continuing until the complaint is decided by the Commission.90 

6.9. Contested Proposal 7B re: GO 95, Rule 35, 

Third Exception 

6.9.1. Summary of Proposal 

Rule 35 of GO 95 requires electric utilities and CIPs to maintain prescribed 

vegetation clearances around their overhead facilities. Rule 35 also lists four 

 

90 The Commission uses the same standard as California courts to decide if a 

temporary restraining order (TRO) should be issued. Under this standard, the 

moving party must show all of the following: (1) Irreparable injury to the moving 

party without the TRO; (2) no harm to the public interest; (3) no substantial harm to 

other interested parties; and (4) a likelihood of prevailing on the merits. 

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exceptions to the prescribed clearances. PG&E, SCE, and SDG&E (together, “the 

Joint Utilities”) propose to amend the Second Exception to replace the word 

“utilities” with “supply or communication company.” This technical revision is 

consistent with the same revision in certain consensus proposals adopted 

previously by today’s decision. 

The Joint Utilities also propose a new Third Exception, with the current 

Third and Fourth Exceptions renumbered. Under the new Third Exception, 

electric utilities and CIPs would not be held responsible for the consequences of 

failing to trim or remove vegetation when a property owner obstructs 

vegetation-management activities and the company can document (1) at least 

one attempt at personal contact with the owner, (2) at least one written 

communication to the owner, and (3) notification to Commission Staff. 

The proposed revisions to Rule 35 are contained in Appendix A of today’s 

decision. The Joint Utilities do not anticipate that their proposal would create 

any additional costs for electric utilities, CIPs, or their customers. 

6.9.2. Position of the Parties 

The main purpose of the Joint Utilities’ proposal is to shift responsibility 

for the failure to perform vegetation management from the electric utilities and 

CIPs to the property owners who obstruct vegetation management. The 

proposal is supported by many CIPs,91 PacifiCorp, and Sierra Pacific. The 

proponents of the proposal agree that shifting responsibility to the obstructing 

property owners is not only fair, it will also reduce obstructions when property 

 

91 The CIPs that support this proposal are AT&T, CTIA, the Small LECS, Sprint, 

Sunesys, SureWest Telephone, T-Mobile, and Verizon. 

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owners realize they will be responsible for the consequences. The end result 

should be improved compliance with vegetation-management requirements and 

a parallel reduction in fire hazards. 

There is no opposition to the Joint Utilities’ proposed technical revisions to 

the Second Exception to Rule 35. The Joint Utilities’ proposal to add a new Third 

Exception is opposed by CPSD, CFBF, MGRA, and TURN. 

The opponents note that the Phase 2 Scoping Memo determined that the 

scope of this proceeding excludes proposals to limit the liability of electric 

utilities and CIPs.92 The opponents assert that the Joint Utilities’ proposal is 

clearly an attempt to limit the electric utilities’ liability. 

The opponents submit there is no guarantee that vegetation management 

will occur if electric utilities and CIPs are allowed to shift responsibility for 

performing vegetation management to the property owners who obstruct 

vegetation management. The only sure outcome, according to the opponents, is 

that electric utilities and CIPs will have no incentive to aggressively conduct 

vegetation management if they can shift liability to the obstructing property 

owners. The end result is likely to be an exacerbation of fire risks. 

CFBF is concerned that the proposal requires only minimal attempts to 

contact property owners, with no requriement that contact actually occur. CFBF 

states that it is unfair to shift legal liabilities to property owners without any 

assurance the affected party has been contacted. 

 

92 Phase 2 Scoping Memo at 8. 

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6.9.3. Discussion 

The primary issue before us is whether to adopt the Joint Utilities’ 

proposal to relieve electric utilities and CIPs of responsibility for the 

consequences of failing to perform vegetation management when a property 

owner obstructs access to overhead facilities. We decline to adopt the proposal 

because it is outside the scope of this proceeding as set forth in the Phase 2 

Scoping Memo: 

[The] scope of Phase 2 excludes matters that are focused on 

reducing utilities’ legal liability. The overarching objective of 

Phase 2 is to consider measures to reduce the fire hazards 

associated with utility facilities. Considering ways to reduce 

liability would divert attention from the main focus of Phase 

2. (Phase 2 Scoping Memo at 8.) 

Even if the proposal were within the scope of this proceeding, we would 

still reject it. In our opinion, the proposal would likely exacerbate fire hazards by 

removing the incentive for electric utilities and CIPs to aggressively pursue 

vegetation management on the properties of recalcitrant landowners. 

We recognize that property owners who obstruct vegetation management 

activities can create a fire hazard that threatens public safety. We believe it is 

reasonable for electric utilities and CIPs to hold the obstructing property owners 

responsible. Therefore, if a property owner obstructs vegetation management, 

and there is a vegetation-related fire or other harm, we encourage the electric 

utilities and CIPs to seek compensation for any costs and liabilities they incur 

from the property owner. The written notices sent to property owners under the 

current Second Exception may include a statement that the electric utility or CIP 

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may seek to recover fire-related costs and liabilities from the property owner.93 

We believe that such notices will provide a strong incentive for property owners 

to allow access to their properties, thus achieving the stated goal of this 

proceeding. Likewise, the electrical utilities and CIPs would continue to have a 

strong motivation to aggressively address safety issues.94 

We adopt the Joint Utilities’ unopposed proposal to revise the Second 

Exception to Rule 35 to replace the generic term “utilities” with the more 

descriptive “supply or communication company.” The adopted revisions to 

Rule 35 are contained in Appendix B of today’s decision. 

6.10. Contested Proposal 8A re: GO 95, Appendix E 

6.10.1. Summary of Proposal 

Electric utilities and CIPs are required by Rule 35 of GO 95 to maintain 

minimum radial clearances between energized bare-line conductors and 

vegetation. The minimum radial clearances are set forth in Table 1 of GO 95. In 

general, the higher the voltage, the greater the required clearance. 

Electric utilities and CIPs periodically trim vegetation around their 

bare-line conductors to maintain the required minimum clearances. By 

necessity, the clearances achieved at the time-of-trim are greater than the 

 

93 The Second Exception states, in relevant part, that “Rule 35 requirements do not 

apply where the utility has made a ‘good faith’ effort to obtain permission to 

trim...but permission was refused or unobtainable. A ‘good faith’ effort shall consist 

of...a written communication, including documentation of mailing or delivery.” 

94 Today’s decision does not reduce electric utilities and CIPs’ legal liability. Rather, it 

facilitates the ability of electric utilities and CIPs to recover their monetary losses 

from the property owners who bear at least some responsibility for such losses. The 

fact that utilities have no guarantee that all fire-related costs will be recovered from 

property owners provides a significant incentive for utilities to reduce fire risks. 

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required minimum clearances so that vegetation growth between trims does not 

intrude on the required minimum clearances. 

Appendix E of GO 95 contains guidelines for the minimum radial 

clearances that should be achieved at time-of-trim, where practical. In the 

Phase 1 Decision, the Commission revised Appendix E to increase the guidelines 

for time-of-trim clearances in the high fire-threat areas of Southern California. 

The Commission also stated that it would consider proposals in Phase 2 to 

further increase the guidelines for minimum time-of-trim clearances.95 

PG&E, SCE, and SDG&E (“the Joint Utilities”) propose to revise 

Appendix E to increase the guidelines for minimum time-of-trim clearances in 

the high fire-threat areas of Southern California from 6.5 feet to 10 feet for 

conductors operating in the range of 2,400 volts to 69,999 volts, and from 10 feet 

to 15 feet for conductors operating in the range of 72,000 volts to 109,999 volts. 

The proposal would also replace the word “volts” in Appendix E with the 

commonly used abbreviation “V”. The proposed revisions to Appendix E are 

shown in Appendix A of today’s decision. 

This proposal would affect both electric utilities and CIPs. The Joint 

Utilities anticipate that their proposal could create a one-time cost for companies 

that do not currently trim to the proposed minimum guidelines. 

6.10.2. Position of the Parties 

The Joint Utilities’ proposal is supported by PacifiCorp and Sierra Pacific. 

The electric IOUs agree that the proposal is a limited and reasonable approach to 

enhancing fire safety in areas of the state where the fire threat is the highest. 

 

95 D.09-08-029 at 29 – 30. 

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The Joint Utilities’ proposal is opposed by LA County, LADWP, and 

MGRA. They contend that because the minimum time-of-trim clearances were 

increased recently by the Phase 1 Decision, there is no need for an additional 

increase. They further contend that because companies have authority under 

Appendix E to exceed the minimum time-of-trim clearances, increasing the 

minimum clearances will not enhance fire safety. 

The opponents of the proposal are concerned that another increase in the 

minimum time-of-term clearances will negatively affect aesthetics, vegetation, 

and efforts to combat global warming. For example, to combat global warming, 

LADWP has distributed more than 100,000 trees. LADWP is concerned that 

these efforts would be adversely affected by the Joint Utilities’ proposal to 

increase the minimum time-of-trim clearances. 

MGRA represents that SDG&E already trims 10 to 15 feet around its 

power lines in the Mussey Grade Road area, which exceeds to the current 

minimum time-of-trim clearances of 6.5 to 10 feet that were adopted by the 

Phase 1 Decision. MGRA is concerned that if greater time-of-trim clearances are 

adopted in Phase 2, SDG&E would feel free to regularly trim beyond the 10 to 15 

feet (depending on voltage) in the Joint Utilities’ proposal, just as SDG&E 

presently feels free to trim beyond the current time-of-trim clearances of 6.5 to 

10 feet (depending on voltage) adopted by the Phase 1 Decision. 

6.10.3. Discussion 

The issue before us is whether to adopt the Joint Utilities’ proposal to 

increase the guidelines for minimum time-of-trim clearances between energized 

bare-line conductors and vegetation in the high fire-threat areas of Southern 

California. In deciding this issue, we note that no party attempted to show that 

the current guidelines for minimum time-of-trim clearances are unsafe. 

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Moreover, Appendix E of GO 95 establishes only minimum time-of-trim 

clearances. Electric utilities have wide latitude under Appendix E to exceed the 

minimum time-of-trim clearances whenever “[r]easonable vegetation 

management practices may make it advantageous to obtain greater clearances.” 

We interpret “reasonable vegetation management practices” as including fire 

safety. Therefore, we decline to adopt the Joint Utilities’ proposal. 

There is no opposition to the Joint Utilities’ proposal to replace the word 

“volts” in Appendix E with the abbreviation “V”. We find the proposed 

technical revision to be reasonable, and we adopt it. The adopted revisions to 

Appendix E of GO 95 are contained in Appendix B of today’s decision. 

6.11. Contested Proposals 8B and 8C re: GO 95, Rule 35, 

Appendix E, Guidelines Only 

6.11.1. Summary of Proposals 

Appendix E of GO 95 provides guidelines for minimum time-of-trim 

clearances between energized bare-line conductors and surrounding vegetation. 

Appendix E also states that “[r]easonable vegetation management practices may 

make it advantageous to obtain greater clearances” than in the guidelines for 

minimum time-of-trim clearances. 

The Phase 2 Workshop Report presents two competing proposals to revise 

Appendix E to provide additional guidance about when it is reasonable to obtain 

greater time-of-trim clearances. One proposal (Contested Proposal 8B) was 

offered by PG&E, SCE, and SDG&E (“the Joint Utilities”). The second proposal 

(Contested Proposal 8C) was offered by CFBF and MGRA. The proposed 

revisions to Appendix E are shown below with strikeout and underline: 

Joint Utilities Proposal 

The radial clearances shown below are recommended

minimum clearances that should be established, at time of 

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trimming, between the vegetation and the energized 

conductors and associated live parts where practicable. 

Reasonable vegetation management practices may make it 

advantageous to obtain greater clearances than those listed 

below: to ensure compliance until the next scheduled 

maintenance. Each utility may determine and apply additional 

appropriate clearances beyond clearances listed below, which 

take into consideration various factors, including: line operating 

voltage, length of span, line sag, planned maintenance cycles, 

location of vegetation within the span, species type, experience 

with particular species, vegetation growth rate and 

characteristics, vegetation management standards and best 

practices, local climate, elevation, and fire risk.

CFBF/MGRA Proposal 

The radial clearances shown below are recommended minimum 

clearances that should be established, at time of trimming, 

between the vegetation and the energized conductors and 

associated live parts where practicable. Reasonable vegetation 

management practices may make it advantageous for the 

purposes of public safety, reliability or tree health to obtain 

greater clearances than those listed below: to ensure compliance 

until the next scheduled maintenance. Each utility may 

determine and apply additional appropriate clearances beyond 

clearances listed below, which take into consideration various 

factors, including: line operating voltage, length of span, line 

sag, planned maintenance cycles, location of vegetation within 

the span, species type, experience with particular species, 

vegetation growth rate and characteristics, vegetation 

management standards and best practices (including when 

feasible appropriate tree crop production manuals), local 

climate, elevation, and fire risk. (Bold font added for emphasis.)

CFBF/MGRA’s proposal is identical to the Joint Utilities’ proposal except 

for the additional text that is shown in the CFBF/MGRA’s proposal in bold font 

above. Both proposals would affect electric utilities and CIPs. Neither proposal 

is expected to create additional costs for electric utilities, CIPs, or other parties. 

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6.11.2. Position of the Parties 

The Joint Utilities’ proposal (Contested Proposal 8B) is supported by 

CMUA, PacifiCorp, Sierra Pacific, and TURN.96 The Joint Utilities state that their 

proposal will not change utility trimming practices. Utilities already consider all 

of the factors listed in the proposal to determine appropriate additional 

clearances at time-of-trim. Rather, the purpose of the Joint Utilities’ proposal is 

to help electric utilities and CIPs deal with property owners who want to limit 

trimming to the minimums set forth in Appendix E. By clarifying that utilities 

may obtain greater clearances, and by identifying the factors that will be 

considered when determining the appropriate additional clearances, the 

Joint Utilities’ proposal will encourage property owners to allow the necessary 

vegetation management work to proceed. 

The CFBF/MGRA proposal (Contested Proposal 8C) is supported by 

LA County, PacifiCorp, Sierra Pacific, and TURN.97 The CFBF/MGRA proposal 

adds two phrases to the Joint Utilities’ proposal. The first phrase – “for the 

purposes of public safety, reliability, or tree health” – explains why trimming 

beyond the specified minimum clearances may be necessary. The seconded 

phrase – “(including when feasible appropriate tree crop production manuals)” - 

captures the importance of using best practices with respect to orchard trees that 

sustain the livelihoods of thousands of farmers. 

The proponents of the CFBF/MGRA proposal contend that because any 

revisions to the time-of-trim guidelines will affect the entire state, not just high 

 

96 PacifiCorp, Sierra Pacific, and TURN support both the Joint Utilities’ proposal and 

CFBF/MGRA’s proposal. 

97 Ditto. 

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fire-threat areas, a broad range of factors should be considered when 

determining minimum time-of-trim clearances. The Joint Utilities’ proposal is 

limited to factors that are important to utilities. In contrast, the CFBF/MGRA 

proposal ensures that the concerns of both utilities and property owners will be 

considered when determining time-of-trim clearances. 

The CFBF/MGRA proposal is opposed by CMUA, LADWP, PG&E, SCE, 

and SDG&E. In general, the opponents are concerned that the CFBF/MGRA 

proposal will provide problem landowners with more reasons to obstruct 

prudent tree-trimming practices. 

6.11.3. Discussion 

The issue before us is whether to adopt either of the two competing 

proposals to revise Appendix E of GO 95 to explain when it is reasonable to 

exceed the minimum time-of-trim clearances around bare-line conductors set 

forth in Appendix E. In deciding this matter, our principle concern is the 

prevention of wildfires and other safety hazards caused by contact between 

vegetation and bare-line conductors operating at high voltages. 

The Joint Utilities’ proposal would revise Appendix E to (1) state that the 

minimum time-of-trim clearances specified in Appendix E are “recommended”; 

(2) state that electric utilities and CIPs may exceed the recommended time-oftrim clearances; and (3) provide a list of factors that electric utilities and CIPs 

should consider when determining whether, and to what extent, it is appropriate 

to exceed the recommended time-of-trim clearances. The proposed factors 

include line sag, vegetation trimming cycles, vegetation growth rates, and 

fire risk. All of the factors are directly related to our public-safety goal of 

keeping high-voltage conductors clear of vegetation. Therefore, we find the Joint 

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Utilities’ proposal is reasonable, and we hereby adopt it. The text of the adopted 

revisions to Appendix E of GO 95 is contained in Appendix B of today’s decision. 

We adopt in part and reject in part the CFBF/MGRA proposal to add to 

Appendix E the phrase “for the purposes of public safety, reliability or tree 

health.” The purpose of the phrase is to summarize when it is appropriate to 

exceed the minimum time-of-trim guidelines. We agree that Appendix E should 

be revised to state that companies may exceed the minimum time-of-trim 

guidelines when necessary for “public safety” and “reliability,” as these reasons 

are directly related to the safety and reliability purposes of GO 95.98 Adding 

these reasons to Appendix E should help electric utilities and CIPs explain to 

property owners why vegetation needs to be trimmed. 

We decline to add “tree health” as a reason for exceeding the minimum 

time-of-trim guidelines, as tree health is not directly related to the overarching 

safety and reliability purposes of GO 95. This does not mean that tree health is 

irrelevant in determining time-of-trim clearances. In fact, the adopted revisions 

to the Appendix E state that electric utilities and CIPs should consider 

“vegetation management standards and best practices” when determining timeof-trim clearances. We interpret this provision as incorporating tree health. 

We decline to adopt CFBF/MGRA’s proposal to add the parenthetical 

“(including when feasible appropriate tree crop production manuals)” as one of 

the factors that may be considered when determining whether to exceed the 

minimum time-of-trim guidelines. The parenthetical is vague and will likely 

 

98 To ensure that the revised text of Appendix E is clear, we have added the modifier 

“service” before the word “reliability,” so that the revised text states “service 

reliability.” 

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cause disagreements between utilities and orchard owners about what 

constitutes an “appropriate” manual. 

Finally, we adopt the recommendation in Cal Fire’s reply comments on the 

proposed decision to revise Appendix E to state that the minimum time-of-trim 

guidelines may be exceeded when necessary to comply with the minimum 

clearance requirements applicable to state responsibility areas (SRAs) pursuant 

to Public Resource Code (PRC) §§ 4102 and 4293.99

6.12. Contested Proposal 9 re: GO 95, Rule 38, Table 2, 

Footnote (aaa) 

6.12.1. Summary of Proposal 

Rule 38 of GO 95 specifies minimum clearances between power lines and 

cables, wires, communication lines, and other conductors. The required 

minimum clearances are set forth in Table 2 of Rule 38. Once installed, the 

required minimum clearances between power lines and other conductors can be 

reduced by 10% during the course of a day due to thermal loading. 

PG&E, SCE, and SDG&E (“the Joint Utilities”) propose to add to Table 2 a 

new Footnote (aaa) that states as follows: 

(aaa) The vertical separation requirement between conductors 

in the adjoining mid-span may or may not require increased 

 

99 PRC § 4102 defines SRAs as areas for which the state has primary financial 

responsibility for preventing and suppressing fires. PRC § 4293, which applies to 

SRAs, states that “any person that owns, controls, operates, or maintains any 

electrical transmission or distribution line upon any mountainous land, or in forestcovered land, brush-covered land, or grass-covered land shall...maintain a clearance 

of the respective distances which are specified in this section in all directions 

between all vegetation and all conductors which are carrying electric current....” 

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vertical separation at the pole based on the sag characteristics 

of the conductors. 

The proposed footnote would apply to the minimum required clearances 

set forth in Table 2, Cases 1 through 13. It would not apply to the minimum 

clearance requirements in Cases 14 through 20. 

The proposed Footnote (aaa) would affect electric utilities and CIPs. The 

Joint Utilities do not anticipate their proposal will create additional costs for 

electric utilities, CIPs, or their customers. 

6.12.2. Position of the Parties 

The Joint Utilities state that maintaining the required minimum clearances 

between power lines and other conductors is vital in areas with combustible 

vegetation, strong winds, and hot weather. Sag can increase significantly with 

high thermal loads. It is important for entities with facilities affixed to the same 

pole and/or crossing under power lines to account for the sag of power lines in 

order to maintain required clearances. The proposed footnote will promote 

safety by reminding responsible personnel that the minimum clearances 

specified in Table 2 of Rule 38 must be met under all expected sag scenarios. 

The Joint Utilities’ proposal is supported by IBEW 1245, LA County, and 

PacifiCorp. IBEW 1245 supports the proposal because it will help to ensure the 

safety of linemen working midspan between power lines and other conductors. 

PacifiCorp supports the proposal because it is consistent with the National 

Electric Safety Code that has been adopted by many of the other states where 

PacifiCorp operates. This will help to reduce the burden on PacifiCorp of 

complying with different requirements in different jurisdictions. 

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The Joint Utilities’ proposed footnote is opposed by CPSD and the 

CIP Coalition. CPSD states that the proposed footnote is unnecessary because 

the required clearances between conductors must be met at all times. 

The CIP Coalition asserts that the proposed footnote is redundant with the 

following provisions in GO 95 regarding conductor clearances and sags: 

• Table 2 of Rule 38 prescribes minimum vertical, horizontal, and 

radial clearances between conductors. 

• Rule 43 prescribes temperature and loading conditions that 

must be considered in determining conductor clearances, 

including certain conditions pertaining to conductor sags. 

• Rule 43.1 requires facilities installed at elevations above 3,000 

feet to be designed for wind pressure of 6 pounds per square 

foot on conductors and 1⁄2 inch of ice. 

• Rule 43.2 requires facilities installed at elevations below 3,000 

feet to be designed for wind pressure of 8 pounds per square 

foot on conductors and no ice. 

• Rule 43.1 and Rule 43.2 require that conductor sag be 

considered at the “normal temperature” of 60oF and at a 

“maximum temperature” of 130oF. 

• Additional sag requirements are set forth in Rule 49.4 C(5), 

Rule 84.5, and Appendix C. Appendix C contains sag curves 

and formulas for determining the sag for different conductor 

types, span lengths, and temperatures. 

• Appendix C specifically states that the sag values contained in 

Appendix C, Table 25 are greater than required to meet 

minimum requirements, but are “considered to be in 

accordance with good practice.” 

• Appendix F contains examples of “typical problems” in line 

construction and explains how conductor sag and tension 

should be determined in hypothetical conditions. 

• Rule 31.1 requires that for all particulars not specified in 

GO 95, “design, construction and maintenance should be done 

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in accordance with accepted good practice for the given local 

conditions known at the time.” 

The CIP Coalition contends that the Joint Utilities did not show that the 

Commission’s existing conductor clearances and sag requirements are unsafe. 

To the contrary, the Commission’s existing requirements are conservative and in 

certain respects exceed the minimum conductor clearance requirements in the 

National Electric Safety Code applicable in most other states. 

6.12.3. Discussion 

The issue before us is whether to adopt the Joint Utilities’ proposal to add 

a new Footnote (aaa) to Table 2 of Rule 38. The purpose of the footnote is to 

remind electric utilities and CIPs to take sag characteristics into account when 

installing new conductors so that required clearances between conductors are 

maintained at all times. 

We agree with CPSD that the proposed footnote is unnecessary, and we 

decline to adopt it. The electric utilities and CIPs are well aware of the sag 

characteristics of conductors and the required minimum clearances between 

conductors. The proposed footnote is purely advisory and adds nothing new. It 

provides no substantive information regarding what types of conductors may 

require extra separation, under what conditions extra separation may be 

required, or how much additional separation may be required. Instead, the 

proposed footnote offers only the vague advice that conductors “may or may not 

require increased vertical separation at the pole based on sag characteristics of 

the conductors.” 

Although we decline to adopt the Joint Utilities’ proposed footnote, we 

remind the electric utilities and CIPs that they are required by GO 95 to take sag 

characteristics into account when installing new conductors to ensure that the 

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minimum clearance requirements between conductors in Table 2 of Rule 38 are 

maintained at all times. We view any failure to maintain minimum conductorto-conductor clearances as a serious fire hazard. Any failure to maintain the 

required minimum clearances shall be deemed either a Level 1 of Level 2 

nonconformance, depending on circumstances, and must be corrected within the 

timeframes specified in Rule 18 (as revised by today’s decision). 

6.13. Contested Proposals 10A and 10B re: GO 95, Rule 

44.2, Rule 44.4, and Appendix I 

6.13.1. Summary of Proposals 

The Phase 1 Decision added Rule 44.2 to GO 95. This rule requires an 

entity that seeks to attach facilities to a structure (e.g., a utility pole) that 

materially increase the load on the structure to perform a loading calculation. 

The purpose of this requirement is to ensure that the attachment of new facilities 

does not reduce the safety factors for the structure below those required by 

Section IV of GO 95. Rule 44.2 also requires entities that own the structure 

and/or have facilities already attached to the structure to provide information 

needed by the entity performing the loading calculations.100 

The Commission stated in the Phase 1 Decision that it would revisit in 

Phase 2 the issues of (1) the time period for exchanging data needed for 

pole-loading calculations, and (2) the definition of what constitutes a “material 

increase” in the load on a structure.101 

 

100 D.09-08-029 at 37-40 and Ordering Paragraphs 3 and 4. 

101 D.09-08-029 at 39-40. 

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The Phase 2 Workshop Report contains two competing proposals to revise 

GO 95 to incorporate timelines and procedures for sharing information needed 

for pole-loading calculations. One proposal was offered by the CIP Coalition 

(Contested Proposal 10A), and the other was offered by the Joint Utilities 

(Contested Proposal 10B). The text of both proposals is contained in Appendix A 

of today’s decision. 

Both proposals would require all entities that own or occupy a joint-use 

pole to provide, upon request, information needed for pole-loading calculations 

to an entity that seeks to attach facilities to the joint-use pole. Both proposals 

would also require the information to be provided as soon as practical, but, 

absent exigent circumstances or mutual agreement, no more than 15 business 

days from the date of request. 

The text of each proposal is nearly identical. The most visible difference 

between the two proposals is that the CIP Coalition’s proposal would place the 

text in a new Rule 44.4. of GO 95, while the Joint Utilities’ proposal would place 

the bulk of the text, including specific requirements, in a new Appendix I of 

GO 95, with a reference to the new Appendix I in a new Rule 44.4. 

There are several other differences between the two proposals. First, the 

Joint Utilities’ proposal would make two technical revisions to the first 

paragraph of Rule 44.2 and delete the second paragraph of Rule 44.2. The 

CIP Coalition agrees with both these proposed revisions, even though these 

revisions are not part of the CIP Coalition’s proposal. 

Second, the CIP Coalition’s proposal directs entities to cooperate by 

“promptly providing or making reasonably available” the information needed 

for pole-loading calculations. The Joint Utilities’ proposal does not include the 

“making reasonably available” provision. 

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Finally, if the entity responsible for a joint-use pole rejects an application to 

attach new facilities to the pole, the CIP Coalition’s proposal would require the 

rejecting entity to explain in the returned application the reasons for the 

rejection. The Joint Utilities’ proposal does not include this requirement. 

Both proposals would apply to all entities that own joint-use poles and/or 

attach facilities to joint-use poles. Neither proposal is expected to result in 

significant costs for electric utilities, CIPs, or their customers. 

6.13.2. Position of the Parties 

The CIP Coalition’s proposal (Contested Proposal 10A) is supported by 

LA County. These same parties oppose the Joint Utilities’ proposal.102 

The CIP Coalition states that the most significant difference between the 

two proposals is that the CIPs believe that cooperation is a fundamental 

necessity that needs to be codified in a new Rule 44.4 of GO 95, whereas the Joint 

Utilities’ proposal would relegate cooperation to the status of “guidelines” in an 

appendix to GO 95. The CIP Coalition is concerned that entities could interpret 

the guidelines as mere recommendations that can be disregarded at will. The 

CIP Coalition asserts that codified requirements are necessary because the 

exchange of information has been problematic in the past. 

The CIP Coalition disagrees with the Joint Utilities’ position, summarized 

below, that the details for sharing information are best left to contracts. The 

problem, according to the CIP Coalition, is that there are no contracts to share 

 

102 Sunesys, a member of the CIP Coalition, takes no position on Contested Proposals 

10A and 10B. 

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information. This only highlights the need for a Commission requirement to 

share information. 

The Joint Utilities’ proposal (Contested Proposal 10B) is supported by 

LADWP, PacifiCorp, and Sierra Pacific. These same parties oppose the 

CIP Coalition’s proposal. 

The proponents of the Joint Utilities’ proposal contend that GO 95 should 

not be rewritten to mandate preordained requirements for sharing information. 

It should be up to the parties to work out the operational details in contracts. 

The Joint Utilities’ proposal to incorporate “guidelines” into GO 95 for sharing 

information strikes the appropriate balance between articulating a requirement 

for cooperation among pole occupants, and allowing flexibility to adapt to varied 

and changing circumstances. 

SCE is convinced that the true purpose of the CIP Coalition’s proposal is to 

undermine the current contractual agreements between SCE and its joint-pole 

partners by inserting into GO 95 the new and unrelated requirement to provide 

reasons for rejecting pole-attachment applications. SCE states that operational 

details among joint-pole users are currently negotiated and memorialized in 

pole-attachment agreements. Putting such details into GO 95 would short-circuit 

the contractual process and throw the current agreements into disarray. 

CPSD supports both proposals, but prefers the CIP Coalition’s proposal 

over the Joint Utilities’ proposal because the CIP Coalition’s proposal codifies the 

provisions for cooperation in GO 95 itself, rather than in guidelines. 

6.13.3. Discussion 

Cooperation among the electric utilities and CIPs is necessary to ensure 

that attachments to joint-use poles comply with the safety factors set forth in 

Rule 44. Such cooperation reduces the chance of pole failures and the associated 

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fire risks. Specific cooperation rules will help ensure that all entities have 

sufficient information to timely evaluate the safety implications of potential 

additions to poles and to timely replace poles when necessary. 

There is no dispute about the need for pole owners and pole occupants to 

cooperate with an entity that seeks to add additional load to a pole. Nor is there 

any dispute about what information needs to be shared for pole-loading 

calculations or how long it should take to provide the information. The only 

dispute is whether the requirement to share information should take the form of 

a new Rule 44.4 in GO 95 (the CIP Coalition’s proposal) or the form of guidelines 

in an appendix to GO 95 (the Joint Utilities’ proposal). 

We conclude that the CIP Coalition’s proposal is superior, and we hereby 

adopt it with certain modifications described below. In our judgment, the public 

interest is better served by a formal rule that requires entities to share 

information needed for pole-loading calculations. As mentioned previously, it is 

important to share information needed for pole-loading calculations to ensure 

that joint-use poles do not become overloaded and fail, which could ignite a fire, 

injure and kill people, and destroy property. The adopted rule is not unduly 

prescriptive, as it reflects the parties’ agreement regarding the timeframe for 

sharing information and the specific information that needs to be shared. The 

adopted rule has the added benefit of ensuring that an entity which submits a 

pole-attachment application is notified why the application has been rejected so 

that appropriate adjustments to the application can be made. 

There is no opposition to the Joint Utilities’ proposal to the extent the 

proposal seeks minor technical revisions to the first paragraph of Rule 44.2 (i.e., 

replacing the word “utility” with the word “entity” in two places) and to delete 

the second paragraph of Rule 44.2 because it duplicates the new Rule 44.4 

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adopted by today’s decision. We find these proposed revisions to be reasonable, 

and we hereby adopt them. The adopted revisions to Rule 44.2 and the text of 

the new Rule 44.4 are contained in Appendix B of today’s decision.103 

We find no merit to SCE’s unsupported assertion that the CIPs will use the 

newly adopted Rule 44.4 to undermine existing pole-attachment agreements. 

Today’s decision requires entities to share information that is needed for poleloading calculations. Both SCE and the CIP Coalition agree that such 

information needs to be shared. We fail to see how a formal requirement to 

share such information could undermine existing pole-attachment agreements. 

As a final matter, we note that the Phase 1 Decision indicated the 

Commission would revisit in Phase 2 the following provision in Ordering 

Paragraph 4 of D.09-08-029 regarding what constitutes a “material increase” in 

load on a structure: 

Ordering Paragraph 4: For purposes of pole loading and 

Rule 44.2 of General Order 95, additional facilities that 

“materially increase the load on a structure” refers to an 

addition which increases the load on a pole by more than 

five percent per installation, or 10 percent over a 12 month 

span of the utility’s or Communication Infrastructure 

Provider’s current load. (D.09-08-029 at 38. Emphasis added) 

Surprisingly, neither the CIP Coalition’s proposal nor the Joint Utilities’ 

proposal addresses the issue of what constitutes a material increase in the load 

on a structure, which triggers the need for a pole-loading calculation. Several 

parties state in their comments on the proposed decision that this issue was 

 

103 One minor grammatical error is corrected in new Rule 44.4. The words “All 

entities” in the first sentence of Rule 44.4 are changed to “Each entity” to match the 

pronoun “its” in Item b. 

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discussed at length during the Phase 2 workshops, but the workshop 

participants were unable to reach an agreement.104 

No party suggests that the current definition of “material increase in load” 

contained in Ordering Paragraph 4 of D.09-08-029 is unreasonable. Therefore, 

we will codify Ordering Paragraph 4 by placing its requirements into Rule 44.2. 

The adopted text of Rule 44.2 is contained in Appendix B of today’s decision. 

6.14. Contested Proposals 11A and 11B re: GO 95, Rule 48 

6.14.1. Summary of Proposals 

Rule 48 of GO 95 specifies the strength of materials and structures for 

overhead facilities. The first two paragraphs of Rule 48 state as follows: 

Structural members and their connection shall be designed 

and constructed so that the structures and parts thereof will 

not fail or be seriously distorted at any load less than their 

maximum working loads (developed under the current 

construction arrangements with loadings as specified in 

Rule 43) multiplied by the safety factor specified in Rule 44. 

Values used for the ultimate strength of material shall comply 

with the safety factors specified in Rule 44. (Emphasis added.) 

The Phase 2 Workshop Report presents two competing proposals related 

to Rule 48. One proposal was offered by the Joint Utilities (Contested Proposal 

11A). The second was offered by CPSD (Contested Proposal 11B). The text of 

both proposals is contained in Appendix A of today’s decision. 

The Joint Utilities propose to revise Rule 48 to remove the “will not fail” 

provision that is highlighted above. CPSD does not propose any changes to 

 

104 See, for example, SDG&E’s comments on the proposed decision at 10 and SCE’s 

comments on the proposed decision at 11. 

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Rule 48 at this time. Instead, CPSD proposes an ordering paragraph that directs 

CPSD to form a technical working group to identify and recommend potential 

changes to Section IV of GO 95 (which consists of Rules 40 through 49) to remove 

antiquated requirements and incorporate modern technologies and practices. 

The Joint Utilities’ proposal is not expected to result in any additional costs 

for electric utilities and CIPs. CPSD’s proposal could result in cost savings 

and/or cost increases, depending on the revisions to Section IV of GO 95 that are 

ultimately adopted. 

6.14.2. Position of the Parties 

The Joint Utilities’ proposal (Contested Proposal 11A) is supported by the 

CIP Coalition, PacifiCorp, and Sierra Pacific. These parties assert that the “will 

not fail” provision in Rule 48 sets an impossible standard because it is not 

feasible to build overhead facilities that will never fail. They also note that a 

similar view was expressed in a letter dated December 14, 2009, from the Deputy 

Director of the Energy Division (Ken Lewis) to the GO 95 Rules Committee that 

asked the Rules Committee to delete the first two paragraphs of Rule 48, stating: 

“These paragraphs impose a design standard that we believe violates standard 

practice and, if literally interpreted, would result in unnecessarily expensive 

transmission and distribution lines.” 

The proponents of the Joint Utilities’ proposal represent that it will not 

affect safety because the proposal does not alter the existing requirement to 

design and construct facilities in accordance with the loading requirements, 

safety factors, and material strengths specified in Rules 43, 44, and 48, 

respectively. Rather, the Joint Utilities’ proposal is a response to CPSD’s 

interpreting the “will not fail” provision in Rule 48 as a mandatory performance 

standard. If a structure fails, CPSD may find that a company has violated the 

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“will not fail” provision in Rule 48 and seek to impose fines, even though the 

structure was designed and constructed in accordance with Rules 43, 44, and 48. 

The Joint Utilities’ proposal is opposed by CPSD, IBEW 1245, and 

LA County. They contend that the Joint Utilities’ proposal will do nothing to 

enhance fire safety. CPSD and LA County believe the real motive for the Joint 

Utilities’ proposal is to remove the legal liability that electric utilities and CIPs 

incur when a structure fails. Under the Joint Utilities proposal, as long as 

companies design and construct their facilities in accordance with the revised 

Rule 48, there would be no legal consequences when facilities fail. For example, 

CPSD asserts that the proposal would allow a utility pole to fail when no wind is 

present without violating GO 95 if the pole had been designed and constructed 

in accordance with Rules 43, 44, and 48. 

CPSD argues that the Joint Utilities’ proposal is an ill-advised approach to 

revising Section IV of GO 95. The various rules in Section IV work 

synergistically to provide appropriate strength requirements. Change to one 

rule necessitates considering change to other rules. This is one reason why CPSD 

urges the Commission to reject the Joint Utilities’ proposal and adopt CPSD’s 

recommendation to conduct a comprehensive review of Section IV. 

IBEW 1245 is concerned that the Joint Utilities’ proposal would hinder the 

ability of journeymen to build safe facilities. IBEW 1245 represents that it is not 

unusual for experienced journeymen building structures to demand 

modifications to make the structures stronger and safer. IBEW 1245 believes the 

proposed rule would militate against in-the-field modifications. 

CPSD recommends that its proposal (Contested Proposal 11B) be adopted 

in lieu of the Joint Utilities’ proposed revisions to Rule 48. CPSD’s proposal 

consists of an ordering paragraph that directs CPSD to form a technical 

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workgroup for the purpose of revising Section IV to remove antiquated 

requirements and incorporate modern technologies and practices, with the 

overall goal of enhancing safety and reliability. CPSD observes that Section IV of 

GO 95 has remained largely unchanged since it was adopted in 1941. 

With certain caveats summarized below, CPSD’s proposal is supported by 

CIPs (CCTA and the CIP Coalition), the electric IOUs (PacifiCorp, PG&E, SCE, 

SDG&E, and Sierra Pacific), DRA, IBEW 1245, and LA County. The CIPs and 

electric IOUs support CPSD’s proposal as an addition to, but not a substitute for, 

the Joint Utilities’ proposed revisions to Rule 48. They recommend that the 

Commission adopt both proposals. 

6.14.3. Discussion 

The issue before us is whether to adopt the Joint Utilities’ proposal and/or 

CPSD’s proposal. We first consider the Joint Utilities’ proposal, followed by 

CPSD’s proposal. 

The Joint Utilities seek to delete the provision in Rule 48 that states utility 

structures must be designed and constructed so they “will not fail” at any load 

less than their maximum working loads specified in Rule 43 multiplied by the 

safety factors specified in Rule 44. The primary reason the Joint Utilities seek to 

delete the “will not fail” provision from Rule 48 is that it purportedly establishes 

an impossible performance standard for the design and construction of facilities. 

This exposes the Joint Utilities to liability if a structure fails, even though the 

structure was designed and constructed to meet the maximum working stresses, 

safety factors, and material strengths specified in Rules 43, 44, and 48. 

We find that the Joint Utilities have not presented a reasonable justification 

for revising Rule 48. The primary purpose of this proceeding is to consider and 

adopt measures to reduce the fire hazards associated with overhead facilities. 

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The Joint Utilities’ proposal is unrelated to this purpose. Furthermore, the scope 

of this proceeding specifically excludes matters that are focused on reducing 

utilities’ legal liability,105 which is apparently what the Joint Utilities’ proposal 

seeks to do. Therefore, we decline to adopt the Joint Utilities’ proposal.106

We next consider CPSD’s proposal for an ordering paragraph that directs 

CPSD to form a technical working group to update Section IV of GO 95 to reflect 

modern materials and practices, with the goal of improving safety and reliability. 

We strongly support the goals of CPSD’s proposal. However, instead of 

convening a technical working group, we will establish a new Phase 3 of this 

proceeding where CPSD and interested parties may present and evaluate 

proposals to modernize Section IV of GO 95 in a facilitated workshop process 

that is modeled on the successful workshops in Phase 2. 

The scope of the Phase 3 workshops shall include revisions to those parts 

of Section IV of GO 95 that pertain to wood materials, structures, and structural 

elements. There is considerable variability in the strength of wood products such 

as utility poles.107 Ideally, the Phase 3 workshops should develop new standards 

that (1) provide electric utilities and CIPs with clear guidance for reliably 

obtaining the prescribed minimum safety factors when using wood products that 

are inherently variable, and (2) can be enforced by CPSD and the Commission. 

 

105 Phase 2 Scoping Ruling at 8. 

106 Today’s decision does not prejudge any issues that are being litigated in 

Investigation 09-01-018 (re: the Malibu Fire Investigation) or that are before the 

Commission in A.08-12-021 (re: SDG&E’s Power Shutoff Plan). 

107 The considerable variability in wood products is due to the fact that trees are living 

organisms subject to many changing influences such as soil conditions, disease, 

weather, and growing space. 

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The Phase 3 workshops will also include the topic of revising Section IV to 

include a new district where there is an elevated risk of power-line fires 

occurring and spreading rapidly. Currently, Rule 43 of GO 95 divides California 

into two districts – a Heavy Loading District and a Light Loading District. The 

Heavy Loading District is all parts of California where the elevation exceeds 

3,000 feet above sea level. The Light Loading District is all parts of California 

where the elevation is 3,000 feet or less. Rule 43 prescribes the minimum wind, 

ice, and temperature loads that must be used to design and construct facilities in 

each district. For example, Rule 43 requires structures in the Heavy Loading 

District and the Light Loading District to be designed and built to withstand a 

horizontal wind load on a cylindrical surface of six pounds per square foot (psf) 

and eight psf, respectively (excluding safety factors). 

The current Heavy and Light Loading Districts were instituted decades 

ago and are intended to provide general standards for the design and 

construction of electric utility and CIP structures throughout California. In 

contrast, the purpose of the new High Fire-Threat District is to designate discrete 

areas where there is an elevated risk of power line fires occurring and spreading 

rapidly, and to specify standards for the design and construction of electric 

utility and CIP facilities in such areas to reduce the risk of power-line fires. 

In the Phase 3 workshops, the parties should define the parameters of the 

new High Fire-Threat District and develop one or more maps that show the 

boundaries of the new District. If possible, these maps should be integrated with 

the fire-threat maps that are discussed later in today’s decision. The workshop 

participants should also develop standards for the design and construction of 

electric utility and CIP facilities in the High Fire-Threat District. These standards 

might include, for example, a wind-load standard in the range of 15 to 20 psf, a 

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requirement to use steel poles instead of wood poles, and increased spacing 

between conductors. Once adopted, the new standards would apply to all new 

construction and reconstruction of electric utility and CIP facilities in the High 

Fire-Threat District. Finally, the workshop participants should assess if any of 

the new standards should apply to existing facilities in the High Fire-Threat 

District in light of Rule 12 and cost-benefit considerations and, if so, develop a 

plan, timeline, and cost estimate for upgrading existing facilities. 

We will appoint a neutral facilitator for the Phase 3 workshops, most likely 

one of the Commission’s Alternative Dispute Resolution ALJs. To determine the 

precise scope of Phase 3, the assigned Commissioner will convene a prehearing 

conference (PHC) and set a schedule for the parties to file written comments 

prior to the PHC regarding the scope and schedule for Phase 3. These comments 

may include proposals to add and/or delete issues from Phase 3. 

The final scope and schedule for Phase 3, including the process and 

procedures for conducting the Phase 3 workshops, will be set forth in the 

assigned Commissioner’s scoping memo for Phase 3. Today’s decision 

constitutes a preliminary scoping memo for Phase 3 and, as such, sets a 

preliminary deadline of 18 months from the issuance date of today’s decision for 

resolving Phase 3 issues pursuant to Pub. Util. Code § 1701.5(b). The final 

deadline will be set by the scoping memo for Phase 3. 

6.15. Contested Proposal 12 re: GO 95, Rule 91.5 

6.15.1. Summary of Proposal 

SDG&E proposes to add a new Rule 91.5 to GO 95 that would require CIPs 

to mark their cables and conductors attached to joint-use poles with information 

that identifies the owner of CIP facilities. The text of the proposed Rule 91.5 is 

contained in Appendix A of today’s decision. 

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SDG&E’s proposed rule would affect all CIPs subject to the Commission’s 

jurisdiction. The proposed rule would create additional costs for CIPs, but 

SDG&E believes the costs are likely to be minimal. 

6.15.2. Position of the Parties 

SDG&E’s proposal is supported by IBEW 1245, LA County, and 

PacifiCorp. The proponents of the proposal believe that marking CIP facilities 

with ownership information will help to quickly identify the owners of CIP 

facilities so that timely notification and correction of safety hazards can occur. 

The proponents state that it is often difficult to identify which CIP is 

responsible for safety hazards on joint-use poles. As a result, repairs are 

delayed, and utility workers and the general public are placed at risk. This 

identification problem is even greater in emergency situations when field crews 

need to reach the owners of particular CIP facilities immediately. Moreover, the 

problem of identifying the owners of CIP facilities is becoming worse due to the 

tremendous growth of the telecommunications industry in recent years. It is 

now common to have four or more CIPs with facilities attached to a single 

joint-use pole. Simple marking of CIP facilities will solve the identification 

problem. 

PacifiCorp and SDG&E note that the proposed requirement to mark CIP 

facilities attached to joint-use poles is consistent with marking requirements in 

both the Northern and Southern Joint Pole Agreements, and with Rule 94.5 of 

GO 95, which requires wireless CIPs to mark their facilities on joint-use poles. 

SDG&E submits that physically marking CIP facilities should not be 

expensive. A simple plastic tag is all that is needed. The proposed rule would 

only apply to new construction and reconstruction, so no additional labor or site 

visits would be needed. The only additional cost would be plastic tags. 

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SDG&E’s proposal is deliberately non-specific so that CIPs can mark their 

facilities in a way that makes sense for them. The method of marking does not 

matter so long as the end result is achieved -- pole owners and pole tenants being 

able to readily identify the owner of particular communication facilities. 

SDG&E disputes the CIP Coalition’s claim, summarized below, that there 

is no evidence that the marking of CIP facilities is needed. During the Phase 2 

workshops, SDG&E informed the participants that it is often difficult for SDG&E 

personnel to identify the CIPs that are responsible for safety hazards on joint-use 

poles. SDG&E sends out notices of hazards as required by Rule 18A, only to 

hear “not us” from the CIPs. As a result, repairs are delayed and SDG&E 

workers and the general public are placed at risk. Physical marking of facilities 

would help to put an end to this sort of run around. 

PacifiCorp and SDG&E dispute the CIP Coalition’s argument, summarized 

below, that electric utilities have all the information they need to track the 

ownership of CIP facilities. While it is true that electric utilities keep records of 

pole occupants for billing and other purposes, these records are not available to 

field personnel and are not designed for the rapid identification of the owner of 

each CIP facility on each pole. 

SDG&E’s proposal is opposed by the CIP Coalition, CMUA, PG&E, and 

SCE. The CIP Coalition declares there is no evidence that marking CIP facilities 

would speed hazard notifications or restoration times. The CIPs do not rely on 

electric utilities to tell them if CIP facilities are disabled – they already know. 

The CIP Coalition asserts that SDG&E already has all the information it 

needs to identify the owners of CIP facilities. SDG&E is the sole owner of its 

poles, and CIPs must lease space from SDG&E pursuant to written agreements. 

As a result, SDG&E has records of exactly what facilities are attached to its poles 

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and who owns those facilities. If SDG&E cannot quickly identify the owners of 

CIP facilities attached to its poles, SDG&E should improve its internal record 

keeping rather than impose a new rule and associated costs on the CIPs. 

The opponents of SDG&E’s proposal agree that it would be costly to 

implement. Not only would CIPs have to install identification tags, they would 

incur ongoing costs to replace tags that fall off, fade over time, or incur other 

damage that renders them useless. In addition, the ownership of CIP facilities 

changes relatively often, so keeping ownership labels current would be 

expensive. The changing ownership also means that those working around CIP 

facilities might not be able to rely on the accuracy of labels. 

Finally, PG&E and SCE state that SDG&E’s proposal lacks specificity. The 

proposal does not indicate how, where, or when CIP facilities will be marked. In 

contrast, Rule 51.6 of GO 95 provides detailed rules for marking conductors over 

750 volts. Among other things, Rule 51.6 specifies the minimum size of markers, 

the color, and the location on the pole. SDG&E’s proposal has none of this detail. 

6.15.3. Discussion 

The issue before us is whether to adopt SDG&E’s proposal to require CIPs 

to mark their cables and conductors on joint-use poles with ownership 

information. Our primary standard for deciding this issue is whether SDG&E’s 

proposal will enhance fire safety. Any adopted marking requirement should 

achieve our goal of fire safety in a cost-effective manner. 

SDG&E’s proposal is consistent with existing requirements. Rule 94.5 of 

GO 95 requires CIPs to mark their wireless facilities on joint-use poles with 

ownership information. Similarly, Rule 44.1(d) of GO 128 requires that: 

All communications equipment in a manhole, or other 

underground splicing chamber with supply cables or 

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conductors, shall be marked if different ownership than the 

supply cables or conductors. 

The Commission has already determined that CIP facilities located in 

underground chambers next to power lines should be physically marked. There 

is no reason to limit this requirement to underground CIP facilities. Indeed, a 

marking requirement for aerial CIP facilities is arguably even more crucial given 

that aerial facilities are more prone to damage from environmental conditions 

(e.g., strong winds and encroaching vegetation) than underground facilities, and 

damaged aerial facilities typically pose a much greater threat to public safety 

than damaged underground facilities. The ability to quickly identify the owner 

of damaged of aerial CIP facilities will likely speed the repair of safety hazards. 

We conclude for the previous reasons that SDG&E’s proposal is 

reasonable, and we adopt it with certain modifications described below. We 

recognize that CIPs will incur costs to mark their facilities and maintain the 

markers. We believe the costs will be relatively modest, as the CIPs can use 

inexpensive and durable plastic tags. The adopted rule may be implemented 

over time as CIPs install new facilities, reconstruct existing facilities, and ascend 

utility poles to perform regular maintenance. Therefore, the rule will not entail 

significant additional costs for labor or site visits. We believe the benefits that 

will accrue from the rapid identification of CIP facilities in terms of worker 

safety, fire safety, and general public safety outweigh the additional costs 

associated with marking CIP facilities. 

We are not persuaded by the CIP Coalition that the new rule is 

unnecessary because SDG&E already knows the owners of the CIP facilities 

attached to its poles. Electric utilities do not maintain information for all 

CIP facilities attached to joint-use poles, particularly for CIP facilities that occupy 

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space that is subleased from another CIP.108 Moreover, field workers need to 

rapidly identify the owners of damaged facilities in emergency situations; they 

should not have to contact office staff to comb through pole-attachment 

agreements to determine the owner of damaged CIP facilities. In addition, 

SDG&E will not always be the first responder to an urgent situation; the first 

responder might be another CIP or other entities. In such instances, facility 

markings would provide the information necessary for the first responder to 

contact the appropriate party to remedy the situation. 

The only shortcoming in SDG&E’s proposal is that it does not specify what 

particular information should be on the markers or where the markers should be 

placed. Consistent with Rule 94.5, each marker shall (1) identify the facility 

owner or operator; (2) provide a 24 hour contact telephone number for 

emergencies or information; (3) be made of weather and corrosion resistant 

material; and (4) be clearly visible to workers who climb the pole or ascend by 

mechanical means. 

6.16. Contested Proposals 13A and 13B re: GO 165, 

Section V and Proposed Ordering Paragraph 

6.16.1. Summary of Proposals 

The Phase 2 Workshop Report presents two competing proposals 

regarding the reporting of fire-related data by electric IOUs. One proposal was 

offered jointly by CPSD and MGRA (Contested Proposal 13A). The second 

proposal was submitted by PG&E. The text of both proposals is contained in 

Appendix A of today’s decision. 

 

108 PG&E reply comments on the proposed decision, at 4. 

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CPSD and MGRA propose to add a new Section V to GO 165 that would 

require each electric IOU to collect information on all fire incidents which are 

attributable to its overhead power lines. The data collected for each incident 

would include the date, time, location, equipment, voltage, fire agencies 

involved, weather conditions, vegetation conditions, and apparent cause. The 

data would be reported annually to CPSD and could be submitted confidentially 

under GO 66-C and Pub. Util. Code § 583. CPSD and MGRA acknowledge that 

their proposal would impose costs on IOUs to collect and report fire-related data, 

but they believe the costs will be insignificant. 

PG&E proposes an ordering paragraph that would require electric utilities 

and CPSD to meet and discus whether CPSD is receiving the fire-related data it 

needs from the electric utilities, whether electric utilities should collect different 

and/or additional data, and whether the data should be provided to CPSD and 

fire agencies such as Cal Fire. State fire agencies would be invited to participate 

in the discussions, but not the CIPs. The electric utilities and CPSD would be 

required to submit a report to the Commission’s Executive Director within nine 

months regarding the results of the discussions. PG&E anticipates that the costs 

of its proposal would be negligible. 

6.16.2. Position of the Parties 

The purpose of the CPSD/MGRA proposal (Contested Proposal 13A) is to 

help prevent catastrophic power-line fires by providing information about the 

causes of power-line fires so that strategies for preventing fires can be devised. 

The proposal would also provide data to evaluate the effectiveness of 

fire-prevention measures adopted in this proceeding and in the future. 

The CPSD/MGRA proposal is supported by DRA and LA County. The 

proponents of the CPSD/MGRA proposal represent that there are no publically 

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available databases maintained by federal, state, or local fire agencies that 

provide the detailed information sought by CPSD and MGRA for all IOU 

power-line fires. Although Cal Fire plans to upgrade its database to include 

more information about fires in California, CPSD and MGRA cite information 

from Cal Fire which indicates that Cal Fire does not intend to collect data that 

can be used to formulate fire-prevention strategies for power-line facilities. 

CPSD, LA County, and MGRA oppose PG&E’s proposed ordering 

paragraph. They see no need to discuss what data CPSD is currently receiving 

and what additional data is needed. CPSD says that it is currently receiving no 

data, and the CPSD/MGRA proposal spells out what data should be provided 

and how it will be used. PG&E’s proposed ordering paragraph would simply 

delay, or prevent altogether, the collection of this important data. 

PG&E’s proposal (Contested Proposal 13B) is supported by the 

CIP Coalition, CMUA, PacifiCorp, SCE, SDG&E, Sierra Pacific, and TURN. In 

general, the proponents of PG&E’s proposal believe it is premature to require 

electric IOUs to report data to CPSD about the causes of power-line fires. 

PG&E’s proposal for CPSD to meet with the electric IOUs and Cal Fire to discuss 

what data is available to satisfy CPSD’s needs would put the Commission in a 

better position to determine what fire-incident data should be reported. If it is 

determined that electric IOUs should report additional fire-incident data, then 

the Commission may adopt a reporting requirement through the resolution 

process as was done with emergency incident reporting in Resolution E-4184. 

The proponents of the PG&E proposal note that electric IOUs were 

required for several years to report all power-line fires that involved vegetation. 

However, in D.06-04-055 the Commission found that the burden of the reporting 

requirement outweighed whatever use was made of the reported information, 

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and the Commission curtailed the requirement. The proponents of the PG&E 

proposal state that there have been no developments since D.06-04-055 that 

justify an expanded fire-reporting requirement. 

The proponents of the PG&E’s proposal identify several publicly available 

collections of fire data that can be mined by CPSD. For instance, Cal Fire 

maintains two databases. One contains information about wildfires, and the 

second contains information about all ignitions in California. Additional 

information is available from the Federal Emergency Management Agency’s 

National Fire Incident Reporting System. PG&E adds that Cal Fire is planning to 

upgrade its databases to provide detailed information regarding the root causes 

for all fires, including power-line fires. PG&E states that if Cal Fire is working on 

a new database capability, there is no need for CPSD to start from scratch. 

Most of the proponents of PG&E’s proposal are opposed to the 

CPSD/MGRA proposal. One major concern is that the CPSD/MGRA proposal 

will impose significant costs on electric IOUs. For example, PG&E estimates that 

it will incur $2 million to implement the CPSD/MGRA proposal. Another 

concern is that information about the causes of power-line fires reported to CPSD 

may be used by plaintiffs’ attorneys to troll for clients, resulting in frivolous 

litigation. The proponents of the PG&E proposal further assert that the 

Commission cannot compel electric IOUs to disclose privileged attorney 

work-product information on the “apparent cause” of a power-line fire, yet that 

is exactly what the CPSD/MGRA proposal requires. 

Sierra Pacific and TURN suggest that experts at state and local fire 

agencies should collect information on fire incidents rather than electric IOUs, 

and that these same fire experts should analyze the data instead of CPSD. 

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6.16.3. Discussion 

The issue before us is whether to adopt either of the two competing 

proposals regarding the reporting of data on power-line fires by electric IOUs. In 

deciding this matter, our principle concern is the reduction in the number of 

power-line fires over time. We must also consider if the benefits of reporting 

data on power-line fires outweigh the attendant costs. 

We agree with CPSD and MGRA that requiring electric IOUs to report 

information on power-line fires would be very useful in formulating fireprevention measures and gauging the effectiveness of the adopted measures. 

The collection and reporting of data is a prerequisite for any serious program of 

sustained and cost-effective fire-safety improvement. 

The problem with the CPSD/MGRA proposal is that it only requires 

electric IOUs to report data on power-line fires. CPSD does not have a firm plan 

for using the data. The proposal does not require CPSD to analyze the data it 

receives or formulate strategies to reduce the number of power-line fires. Nor 

does the proposal identify a procedure for CPSD to submit fire-safety 

recommendations to the Commission, for the interested parties and the 

Commission to evaluate the proposals, and for the Commission to approve or 

reject the proposals. 

We are mindful of the Commission’s previous experience with reporting 

of data on power-line fires. In D.98-07-097, the Commission required electric 

utilities to report all power-line fires involving vegetation, no matter how small. 

Subsequently, in D.06-04-055 the Commission narrowed the scope of reportable 

power-line fires to those that (1) result in a fatality or injury requiring 

hospitalization; (2) receive significant public attention or media coverage; or 

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(3) cause property damage of $20,000 or more. One of the reasons cited for 

curtailing the scope of reported power-line fires was “limited staff resources.109” 

We are not convinced that the CPSD/MGRA proposal to require IOUs to 

report detailed data on all power-line fires will be any more successful than our 

previous effort in this regard, particularly given the lack of a concrete plan to use 

the reported information. Therefore, we decline to adopt the CPSD/MGRA 

proposal at this time. 

Although we decline to adopt the proposal, we agree with the intent of the 

proposal. There are many power-line fires every year. PG&E alone experiences 

approximately 75 vegetation-related fires each year.110 The threat to public safety 

posed by a power-line fire depends largely on the wind, humidity, and 

vegetation conditions at the time and place of the fire. The fact that there are 

scores of power-line fires annually for a single IOU indicates there is a credible 

risk that power-line fires will eventually occur under hazardous conditions. 

For the preceding reasons, we conclude that it is in the public interest to 

hold facilitated workshops in Phase 3 where the parties111 can jointly develop a 

plan for CPSD to collect data on power-line fires from the electric IOUs, analyze 

the data, and use this information to formulate measures to reduce the number 

of fires ignited by power lines. The plan may include a proposed requirement 

for electric IOUs to provide other data to CPSD that would useful in identifying, 

assessing, and abating systemic fire-safety risks of overhead power lines and 

 

109 D.06-04-055 at 7. 

110 PG&E Reply Brief at 14, fn. 32. 

111 We encourage the participation of electric IOUs, CIPs, MGRA, Cal Fire, and other 

state and local fire-safety agencies in the Phase 3 workshops. 

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aerial communication facilities in close proximity to power lines. Such data may 

include, for example, data on the IOUs’ maintenance programs, inspection 

activities, corrective actions, and intercompany notices of safety hazards.112 

The plan developed by the workshop participants should provide clear 

guidance regarding the specific information that electric IOUs should report 

about the causes of power-line fires.113 CPSD needs to receive enough detail 

about the causes of fires so that effective prevention measures can be developed. 

On the other hand, there is no apparent need for CPSD to receive data on powerline fires from the IOUs that is either privileged or readily available from 

publicly accessible databases.114 

The exact scope and schedule for Phase 3, including the process and 

procedures for conducting the Phase 3 workshops, will be set forth in the 

assigned Commissioner’s scoping memo for Phase 3. 

We decline to adopt PG&E’s proposed ordering paragraph to require 

CPSD to meet and confer with electric IOUs to discuss what data, if any, should 

be provided to CPSD. PG&E’s proposal does not go far enough. Today’s 

decision finds that electric IOUs should provide data on power-line fires to CPSD 

 

112 Electric utilities are required by Rule 18A of GO 95 to create and retain auditable 

records on their maintenance programs, inspection activities, and corrective actions. 

Rule 18B requires that if one company discovers a safety hazard with respect to 

another company’s facilities during routine inspections, the first company must 

notify the second company of the hazard within a prescribed timeframe. 

113 The CPSD/MGRA proposal requires IOUs to report the “apparent cause” of a 

power line fire, but provides no guidance about the level of detail that should be 

reported on the apparent cause. 

114 Today’s decision does not prevent or prejudge any requests by CPSD to compel the 

disclosure of information that an electric IOU has labeled as privileged. 

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once the workshop participants have developed, and we have approved, a 

concrete plan for using such data. 

It is premature to address the other issues raised by the opponents of the 

CPSD/MGRA proposal, such as the cost of the proposal, duplication with 

databases maintained by fire-safety agencies, the ability of plaintiffs’ attorneys to 

access the data reported to CPSD, and other issues. Hopefully, these issues will 

be resolved during the Phase 3 workshops. Any unresolved issues are better 

addressed after the Phase 3 workshop participants submit a plan for the 

collection and use of fire-incident data.115 We may reject the forthcoming plan if 

we find that the public-safety benefits of the plan are outweighed by its costs and 

other disadvantages. 

6.17. Contested Proposals 14A, 14B, and 14C re: 

Fire-Threat Maps 

6.17.1. Summary of Proposals 

The Phase 1 Decision ordered the CIPs to conduct patrol inspections of 

specified overhead facilities in those areas of Southern California that are 

designated as Extreme and Very High Fire Zones on Cal Fire’s Fire and Resource 

Assessment Program Fire Threat Map (FRAP Map). The Phase 1 Decision also 

determined that the Commission would consider in Phase 2 whether the 

FRAP Map should be used to designate areas for CIP inspections in Northern 

California.116 The Phase 2 Scoping Memo established the scope of Phase 2 as 

including (1) whether the FRAP Map or other fire-threat maps should be used to 

 

115 The workshop participants may present alternative plans and recommendations if a 

consensus cannot be reached. 

116 D.09-08-029 at 23 and Ordering Paragraph 1. 

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designate areas for CIP inspections in Northern California, and (2) whether 

better maps could be developed.117 

The Phase 2 Workshop Report presents two competing proposals 

regarding fire-threat maps. The first proposal was submitted jointly by CPSD 

and MGRA (Contested Proposal 14A). The second proposal was submitted by 

the CIP Coalition (Contested Proposals 14B and 14C). The difference between 

Contested Proposals 14B and 14C is not meaningful for the purpose of today’s 

decision, and the two proposals will be treated as a single proposal. The text of 

the competing proposals is contained in Appendix A of today’s decision. 

6.17.1.1 Summary of Contested Proposal 14A 

The CPSD/MGRA proposal consists of an ordering paragraph that would 

require electric IOUs and CIPs to prepare a work plan, in consultation with 

CPSD and Cal Fire, for the development of statewide, high-resolution maps that 

combine wind and vegetation data to identify areas where there is a high risk of 

catastrophic power-line fires occurring. The fire-threat maps would be used to 

determine inspection and maintenance cycles in all cases where geographic 

locations and maps are mentioned in GO 95 and GO 165. 

The proposed work plan would include (1) a process for developing 

fire-threat maps; (2) an estimate of the time and costs to develop and maintain 

fire-threat maps; (3) a process for updating fire-threat maps to incorporate 

changes to the underlying data and new analytical techniques; and (4) a list of 

actions the Commission would need to take to enable the creation, adoption, and 

implementation of utility-specific maps. The electric IOUs and CIPs would be 

 

117 Phase 2 Scoping Memo at 5 – 6, Items 11, 12, and 15. 

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required to submit a report to the Commission on the status of the work plan 

within six months. Upon completion of the work plan, the Commission would 

decide whether to order the electric IOUs and CIPs to fund the development and 

maintenance of fire-threat maps. The fire-threat maps adopted in Phase 1 

and/or Phase 2 would remain in effect until further order by the Commission. 

The electric IOUs and CIPs would be required to fund the creation of the 

work plan. CPSD and MGRA believe the costs to create the work plan would be 

small. CPSD and MGRA did not provide an estimate of the costs to develop, 

implement, and maintain fire-threat maps. 

6.17.1.2 Summary of Contested Proposals 14B and 14C 

The CIP Coalition’s proposal would add a new provision to Rule 31.2 of 

GO 95 that specifies the areas in Northern California where aerial CIP facilities 

would be subject to the inspection cycles set forth in Rule 31.2. The centerpiece 

of the CIP Coalition’s proposal is a fire-threat map that was developed jointly by 

the University of California at Berkeley and Reax Engineering Inc., a consulting 

company (the “Reax Map”). 

The CIP Coalition’s proposal would apply only to aerial CIP facilities in 

the areas of Northern California that are designated as Threat Class 3 and Class 4 

on the Reax Map, the two highest fire-threat categories. The FRAP Map would 

continue to be used to designate the high fire-threat areas in Southern California 

where overhead CIP facilities would be subject the inspection cycles set forth in 

Rule 31.2. The CIP Coalition’s proposal would not apply to electric utilities. 

The costs to develop the Reax Map have already been incurred and will 

not be recovered directly from customers. Future costs to implement the map 

may be recovered, to the extent possible, in market-based prices for CIP services. 

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6.17.2. Position of the Parties 

The intent of the CPSD/MGRA proposal (Contested Proposal 14A) is to 

establish a scientifically sound process for the development of high-resolution 

maps to identify areas where catastrophic power-line fires are most likely to 

occur. The maps would be developed in consultation with Cal Fire and peer 

reviewed by fire-safety experts. Once developed, the maps would be used by 

electric IOUs and CIPs to implement the augmented inspection, maintenance, 

and vegetation management requirements of GO 95 and GO 165 for high 

fire-threat areas. The maps could also be used for the following purposes: 

• Identify areas where it would be beneficial to employ 

additional fire-prevention measures such as burying power 

lines, strengthening facilities to withstand stronger winds, 

adding insulation to conductors, or rerouting. 

• Plan new power-line facilities and routes in a manner that 

minimizes fire risk. 

• Maximize fire-prevention benefits from limited funds. 

The CPSD/MGRA proposal is supported by DRA and LA County. The 

proponents of the proposal believe it is vital to replace the FRAP Map that was 

adopted by the Phase 1 Decision for CIP inspection purposes in 

Southern California, as Cal Fire has warned that the FRAP Map is not suited for 

this purpose. 

The CPSD/MGRA proposal is opposed by the CIP Coalition, LADWP, 

PacifiCorp, PG&E, SCE, SDG&E, Sierra Pacific, and TURN. Most of the 

opponents see no need to develop new fire-threat maps because adequate maps 

are either in place or waiting for Commission approval. These include (1) the 

FRAP Map that was adopted by the Phase 1 Decision, (2) the Reax Map that is 

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before the Commission in Phase 2, and (3) a fire-threat map that SDG&E has 

developed and implemented for its own use. 

Several of the opponents are concerned that the CPSD/MGRA proposal 

will be costly to implement. For example, the CIP Coalition recently 

implemented the FRAP Map in Southern California. Switching to the new 

fire-threat maps contemplated by the CPSD/MGRA proposal would require the 

CIPs to reconfigure their inspection efforts around the new maps. 

PacifiCorp and Sierra Pacific argue that they should not have to bear any 

costs for the fire-threat maps proposed by CPSD and MGRA because the 

proposed maps would not reduce fire risks in their service territories. This is 

because the fire-threat maps envisioned by CPSD and MGRA would rely 

primarily on wind data to designate high fire-threat areas. The strongest winds 

in PacifiCorp’s and Sierra Pacific’s service territories occur during the winter 

months when the fire danger is low. 

TURN is concerned that the high-resolution maps envisioned by CPSD 

and MGRA would reduce fire safety. Presumably, the high-resolution maps 

would pinpoint the areas where fire risk-mitigation activities should take place. 

Absent high-resolution maps, fire-prevention measures would need to be 

deployed over a larger area, which has the salutary effect of providing a better 

margin of safety. 

SDG&E represents that it has already developed and implemented a 

fire-threat map for its service territory. Consequently, SDG&E has no need for 

the new fire-threat maps proposed by CPSD and MGRA. SDG&E also believes 

that its fire-threat map is better than the one contemplated by the CPSD/MGRA 

proposal. Compared to the CPSD/MGRA proposal, SDG&E used a more 

comprehensive risk assessment that included wind, vegetation, topography, 

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historical fires, downwind impacts, and practical considerations for operations 

and maintenance of facilities. 

If the Commission decides to develop a new fire-threat map, PacifiCorp 

and PG&E submit that it is reasonable to allow CPSD to review the Reax Map 

and then have the Commission consider the adoption of the Reax Map for use by 

the CIPs. This effort may be appropriate for a Phase 3 of this proceeding. 

The CIP Coalition urges the Commission to adopt the Reax Map, which 

provides a scientifically-based geographic delineation of high fire-threat areas in 

Northern California.118 The methodology used to create the Reax Map, while 

based on the FRAP Map, applied several enhancements to assess the factors 

leading to fires associated with joint-use poles, such as local terrain and weather, 

wind-induced pole/line failure, ignition sources, and fire-spread behavior. The 

end result is a fire-threat map that incorporates more extensive and more recent 

data than the FRAP Map, and more accurately delineates the geographic areas in 

Northern California where there is a high fire threat.119 

The CIP Coalition asserts that the Commission does not require peer 

review of expert reports submitted to the Commission. To the contrary, it is the 

Commission’s practice to conduct its own review of expert reports and to issue 

decisions addressing the merits of such reports. That is not to say that the 

 

118 Cox, a member of the CIP Coalition, abstains from taking a position on Contested 

Proposals 14A, 14B, and 14C. 

119 The Reax Map and a report describing the methodology that was used to develop 

the Reax Map are attached to the Phase 2 Workshop Report as Appendix E. On 

September 15, 2010, David Rich, principal engineer at Reax Engineering Inc., filed a 

verification of the contents of the Reax Map and report in accordance with Rule 1.11 

of the Commission’s Rules of Practice and Procedure. 

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Commission’s adoption of the Reax Map should forestall additional evaluation 

of the map. Interested parties such as CPSD, MGRA, and Cal Fire can continue 

to assess the Reax Map. If they find something that might warrant a change to 

the Reax Map, they can bring such changes to the Commission attention with a 

petition to modify the Phase 2 decision. 

The CIP Coalition’s proposal (Contested Proposals 14A and 14B) is 

supported by PacifiCorp. No other parties expressed support for the 

CIP Coalition’s proposal in their briefs. 

CPSD and MGRA do not oppose the Reax Map at this time, but they are 

concerned that the map has not been reviewed by experts. TURN agrees with 

CPSD and MGRA that any fire-threat map should be evaluated by experts prior 

to adoption by the Commission.120 Nonetheless, CPSD and MGRA are optimistic 

that the Reax Map could be the foundation for a statewide fire-threat map. They 

note that the Reax Engineering Inc., has the capability of extending the Reax Map 

for Northern California to Southern California. 

MGRA recommends using the Reax Map on an interim basis in Northern 

California for CIP inspections purposes until a formal peer review of the Reax 

Map is complete. MGRA also supports using the SDG&E Map on an interim 

basis for SDG&E’s service territory pending a review of the SDG&E Map. 

6.17.3. Position of Cal Fire 

Cal Fire opposed the Commission’s decision in Phase 1 to use Cal Fire’s 

FRAP Map to identify areas where the threat of power-line fires is most acute in 

Southern California. The issues raised by Cal Fire related to the deficiencies of 

 

120 TURN opposes both the CPSD/MGRA proposal and the CIP Coalition proposal. 

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map resolution and accuracy, model formulation, underlying data, and the 

overall inappropriate application of the FRAP Map. Cal Fire warns that the 

FRAP Map remains ill-suited for the uses adopted by the Phase 1 Decision and 

the uses contemplated by various parties in Phase 2. 

Cal Fire supports the CPSD/MGRA proposal to develop fire-threat maps 

that meet the needs of the Commission, utilities, and other stakeholders. Subject 

to staff availability and the recovery of significant costs, Cal Fire is willing to: 

• Participate with Commission staff, utilities, and other 

stakeholders in preparing a work plan for the development 

and maintenance of appropriate fire-threat maps. 

• Participate in a review of any fire-threat maps that may be 

developed as a result of the work plan. 

Cal Fire states that the Reax Map could be an appropriate starting point for 

developing a work plan, but Cal Fire has not reviewed the Reax Map and has no 

opinion on the map. Cal Fire is willing to participate in a peer review of the 

Reax Map to the extent that staff and other resources are available. 

Cal Fire notes that it has inspection and law enforcement responsibilities 

regarding utilities, power lines, and fires. Given these mandated responsibilities, 

Cal Fire states that it cannot approve any utility-related fire-threat maps. Rather, 

the Commission should have the responsibility to approve maps that are 

developed as part of its regulatory jurisdiction. 

6.17.4. Discussion 

The issue before us is whether to adopt the CPSD/MGRA proposal or the 

CIP Coalition proposal regarding fire-threat maps. CPSD and MGRA seek to 

establish a process for the development and adoption of fire-threat maps for 

various uses by the CIPs and electric IOUs. The CIP Coalition seeks the 

immediate adoption of the Reax Map for the narrow purpose of delineating the 

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geographic area of CIP inspections in Northern California under Rule 31.2 of 

GO 95. In deciding this issue, it is helpful to review the intended use of 

fire-threat maps. 

The function of fire-threat maps is to accurately designate geographic 

areas where power-line fires are more likely to be ignited and spread rapidly, 

thereby posing an increased risk of catastrophic wildfires. To reduce the risk of 

power-line fires occurring in high fire-threat areas, the Phase 1 Decision and 

today’s decision together adopt the following measures that rely on fire-threat 

maps: 

• GO 95, Rule 18A, requires electric utilities and CIPs to place a 

high priority on the correction of significant fire-safety hazards 

in areas of Southern California that are designated as Extreme 

and Very High Fire Threat Zones on the FRAP Map.121 

• GO 95, Rules 31.2, 80.1A, and 90.1B establish the minimum 

frequency for patrol inspections, detailed inspections, and 

intrusive inspections of aerial communication facilities located 

in close proximity to power lines in any area of the state that is 

designated as a high fire-threat on the relevant fire-threat map 

adopted by the Commission. 

• GO 95, Rule 35 and Appendix E, specifies increased time-oftrim clearances between vegetation and energized conductors 

in areas of Southern California that are designated as Extreme 

and Very High Fire Threat Zones on the FRAP Map. 

• GO 95, Rule 35, Table 1, Case 14, requires increased radial 

clearances between bare-line conductors and vegetation in 

areas of Southern California that are designated as Extreme 

and Very High Fire Threat Zones on the FRAP Map. 

 

121 Today’s decision defines Southern California as Imperial, Los Angeles, Orange, 

Riverside, Santa Barbara, San Bernardino, San Diego, and Ventura Counties. 

Northern California is defined as all other counties in California. 

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• GO 165, Appendix A, Table 1, requires more frequent patrol 

inspections of overhead power-line facilities in rural areas of 

Southern California that are designated as Extreme and Very 

High Fire Threat Zones on the FRAP Map. 

• GO 166, Standard 1.E., requires electric utilities in Southern 

California to develop and submit a plan to reduce the risk of 

fire ignitions by overhead power-line facilities located in high 

fire-threat areas during extreme fire-weather events. Electric 

utilities in Northern California must also develop and submit a 

plan if the utility has overhead power-line facilities that are 

located in an area that is (1) designated as a high fire-threat 

area on a fire-threat map adopted by the Commission, and 

(2) subject to extreme fire-weather events. 

The success of the previously identified measures at reducing the risk of 

catastrophic power-line fires depends on maps that accurately identify areas 

where power line fires are most likely to occur and spread rapidly. Stated 

differently, we cannot effectively mitigate the risk of power-line fires unless we 

know where the risks are located. 

The Phase 1 Decision adopted the FRAP Map to establish inspection 

cycles, prioritize repairs, and determine vegetation clearances in the high firethreat areas of Southern California.122 However, the FRAP Map was adopted 

against Cal Fire’s advice that the map is ill-suited for identifying high-risk areas 

for power-line fires.123 The Phase 1 Decision nevertheless adopted the 

FRAP Map because there was no better fire-threat map available at the time. 

We note that the definition of “high fire-threat areas” used by the Phase 1 

Decision and today’s decision includes those areas that are designated as 

 

122 D.09-08-029 at pp. 15, 21, and 34. 

123 Cal Fire Phase 1 Comments filed on March 27, 2009, at pp. 2 - 5. 

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“Extreme” and “Very High” fire threat zones on the FRAP Map, but inexplicably 

excludes those areas that are designated as “High” fire threat zones on the 

FRAP Map. This incongruous definition of “high fire-threat areas” is used by 

several measures adopted by today’s decision, including GO 95, Rules 31.2, 

80.1A, and 90.1B. This incongruity must be resolved in the map(s) adopted in 

Phase 3 of this proceeding to ensure that all truly “high” threat-fire zones are 

included in the ”high fire-threat areas” shown on the map(s). 

Unlike the FRAP Map, the Reax Map and the SDG&E Map are specifically 

designed to identify areas where there is a heightened risk of power-line fires. 

Both maps take into account the major factors that contribute to the ignition and 

spread of power-line fires, including wind, vegetation, and topography. 

However, while both the Reax Map and SDG&E Map show promise, neither has 

been reviewed by the parties to this proceeding or by neutral fire-safety experts 

such as Cal Fire. Given the vital public safety issues involved, we conclude that 

the Reax Map and the SDG&E Map must be reviewed by neutral experts before 

these maps are adopted on a permanent basis. 

The Reax Map and the SDG&E Map are also limited in the geographic 

areas they cover. The Reax Map covers only Northern California, and the 

SDG&E Map is confined to SDG&E’s service territory. It is imperative that 

accurate fire-threat maps be developed for all of Southern California, as this is 

the area of the state with the greatest risk of catastrophic power-line fires. 

For the preceding reasons, we conclude that it is reasonable to adopt the 

major elements of the CPSD/MGRA proposal. We will order the CIPs and 

electric IOUs to participate in a workshop with CPSD and Cal Fire for the 

purpose of preparing a detailed work plan to develop and adopt statewide, 

high-resolution maps that accurately designate areas where there is a high threat 

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of power-line fires occurring and spreading rapidly. We also invite the other 

parties in this proceeding and the Lawrence Livermore National Laboratory to 

participate in the workshops.124 The fire-threat maps must be specifically 

designed for use in conjunction with the previously identified fire-prevention 

measures adopted by the Phase 1 Decision and today’s decision. Although we 

would prefer a single statewide fire-threat map, this is not necessary. The 

workshop should not exclude any fire-threat maps from consideration. 

However, our expectation is that if multiple fire-threat maps are adopted, these 

maps should utilize consistent terminology and criteria in identifying fire-threat 

areas. Such consistency will avoid disparate application of the measures 

adopted by today’s decision in different regions of the state. 

As the first step towards the adoption of permanent fire-threat maps, we 

will establish facilitated workshops in Phase 3 of this proceeding where the 

parties shall jointly prepare a report that contains the following: 

• A proposed work plan for the development of accurate, 

high resolution fire-threat maps that cover the entire state. The 

purpose of the fire-threat maps is to identify the specific 

geographic areas where power-line fires are more likely to 

occur and spread rapidly. The detailed proposal shall address 

the option of reviewing and adopting the Reax Map and/or 

the SDG&E Map for regional or statewide use. 

• Recommendations for obtaining assistance from Cal Fire, 

Lawrence Livermore National Laboratory, and other neutral 

 

124 On June 14, 2011, Dr. S. Julio Friedmann, Director, Carbon Management 

Program for the Lawrence Livermore National Laboratory (LLNL), sent an 

email to the service list for this proceeding in which Dr. Friedmann stated that LLNL 

has “unique capabilities and knowledge that could help in [fire-threat] map 

assessment or map creation.” 

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experts in the development and review of fire-threat maps, 

including the Reax Map and the SDG&E Map. 

• Estimated costs and proposed funding sources for the 

development, expert review, implementation, and 

maintenance of fire-threat maps. 

• A proposed schedule and a list of milestones for the 

development, review, adoption, implementation, and periodic 

updates of fire-threat maps. 

The report may include alternative work plans and recommendations if 

the workshop participants cannot reach a consensus. 

The exact scope and schedule for Phase 3, including the process and 

procedures for conducting the Phase 3 workshops, will be set forth in the 

assigned Commissioner’s scoping memo for Phase 3. 

Until permanent fire-threat maps are adopted in Phase 3, the CIPs and 

electric utilities shall use the FRAP Map, Reax Map, and SDG&E Map on an 

interim basis to implement the fire-prevention measures adopted by the Phase 1 

Decision and today’s decision. The CIPs shall use Reax Map in Northern 

California and the FRAP Map in Southern California. The electric utilities other 

than SDG&E shall use the Reax Map in Northern California and the FRAP Map 

in Southern California. SDG&E may use its own fire-threat map. Copies of the 

FRAP Map and Reax Map are contained in Appendix C of today’s decision. The 

CIPs shall make the high-definition Reax Map available to other parties for the 

purposes specified in today’s decision.125 SDG&E shall provide a copy of its 

fire-threat map to any party that requests it. 

 

125 Electric utilities in Northern California may record in their Fire Hazard Prevention 

Memorandum Accounts (FHPMAs) any licensing fees and similar costs they incur to 

Footnote continued on next page 

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The adopted fire-prevention measures shall be implemented on an interim 

basis in areas that are designated as Extreme and Very High Fire Threat Zones 

on the FRAP Map and SDG&E Map, and in areas that are designated as Threat 

Class 3 and Threat Class 4 on the Reax Map. The boundaries should be broadly 

construed. The CIPs and electric utilities should use their own expertise and 

judgment to determine if local conditions require them to adjust the boundaries 

of the relevant map. 

We recognize that the interim maps may be flawed. However, we 

conclude that the threat of catastrophic power-line fires is so great that the public 

interest is better served by requiring the CIPs and electric utilities to implement 

the adopted fire-prevention measures using the available maps rather than 

waiting for the development and adoption of permanent maps in Phase 3. While 

there is some risk in using the un-reviewed Reax Map and SDG&E Map on an 

interim basis, we believe the risk is low, as both maps are designed to identify 

areas where there is a high risk of catastrophic power-line fires. 

We are not persuaded by the assertion from several parties that the 

FRAP Map is sufficient for the purposes intended by the Phase 1 Decision and 

today’s decision. We believe it would be imprudent to adopt the FRAP Map on a 

permanent basis for the purpose of designating areas where the adopted fireprevention measures should be deployed when the state agency that created the 

FRAP Map warns against its use for this very purpose. 

 

access the Reax Map and seek to recover such costs in the same manner as other 

costs recorded in their FHPMAs. 

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PacifiCorp and Sierra Pacific argue unpersuasively that they should not 

have to pay any costs for the development of new fire-threat maps because there 

is no threat of catastrophic power-line fires in their service territories. A 

comparison of maps showing PacifiCorp’s and Sierra Pacific’s service 

territories126 with the Reax Map in Appendix C of today’s decision reveals that 

there are large swaths of their service territories that are designated as 

Fire Threat Class 3 on the Reax Map, and several pockets of their service 

territories that are designated as Fire Threat Class 4. 

We are not persuaded by TURN that the adoption of high-resolution maps 

which accurately pinpoint the areas of elevated fire risk will reduce safety by 

decreasing the size of the areas where CIPs and electric utilities are required to 

implement fire-prevention measures. The high-resolution maps required by 

today’s decision are essential for the effective deployment of many of the 

fire-prevention measures adopted in this proceeding. The FRAP Map is illsuited for this purpose, as Cal Fire readily acknowledges. In our judgment, the 

ability to accurately target high fire-threat areas will enhance public safety by 

reducing the number of power-line fires. 

Finally, several parties contend that it will be too costly to develop and 

implement new fire-threat maps. As stated previously, the fire-threat maps 

required by today’s decision are an essential tool for the successful deployment 

of the fire-prevention measures adopted in this proceeding. We find that the 

 

126 A map that shows PacifiCorp’s and Sierra Pacific’s service territories is available at 

http://www.energy.ca.gov/2007_energypolicy/documents/2007-05-

15_workshop/presentations/Electric%20Utility%20Service%20Areas%205-10-

07.pdf. We take official notice of this document pursuant to Rule 13.9 of the 

Commission’s Rules of Practice and Procedure. 

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public-safety benefits from the reduced risk of catastrophic power-line fires more 

than offset the cost of developing and implementing high-resolution maps that 

accurately designate the areas where there is an elevated threat of catastrophic 

power-line fires occurring. 

6.18. Record Retention 

All of the inspection and repair rules proposed by the parties retain the 

existing record retention requirements. In general, the existing rules require 

CIPs and electric utilities to retain records of their inspections and repairs for a 

five-year period. We believe that a longer record-retention period is needed in 

order to ensure there is sufficient information to conduct a thorough forensic 

analysis in the event there is a serious safety-related incident with overhead 

power lines and/or CIP facilities. Therefore, we will adopt a general 

requirement to create and maintain for ten (10) years records of all inspections 

and repairs of overhead facilities. In the case of intrusive inspections of wood 

poles, we will require records of such inspections, and any repairs that result 

from such inspections, to be maintained for the life of the pole. This new 

record-retention requirement applies to records currently in an entity’s 

possession and records created on or after the date of today’s decision. 

6.19. Commission Jurisdiction and Publicly Owned Utilities 

CMUA and LADWP ask the Commission to clarify the extent of its 

enforcement powers under Pub. Util. Code §§ 8037 and 8056 over publicly 

owned utilities (POUs) with respect to several of the rules and regulations 

adopted by the Phase 1 Decision and today’s decision. We interpret CMUA and 

LADWP’s request as seeking an advisory opinion. Like the courts, we have a 

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long-standing policy against issuing advisory opinions,127 and we decline to do 

so here.128 

6.20. Cost Recovery 

The Phase 1 Decision provided the following guidance regarding the 

recovery of costs incurred electric utilities, CIPs, and other entities to implement 

the regulations adopted in this proceeding: 

We find that each cost-of-service regulated utility is entitled 

to recover reasonable costs prudently incurred to comply 

with the changes to the Commission’s rules adopted today. 

To be clear, we do not find today that all costs incurred to 

comply with the revised rules will be automatically assumed 

to be reasonable but that, after the Commission verifies the 

reasonableness of costs, recovery will be permitted. We 

direct each cost-of-service regulated utility to record its costs 

in a memorandum account to avoid retroactive ratemaking. 

We will address costs more fully in [Phase 2] and expect 

cost-of-service regulated utilities to provide cost data. We will 

decide the appropriate forum for seeking recovery of these 

costs in [Phase 2]. In [Phase 2], we will also develop an 

appropriate tracking mechanism for these additional costs 

and decide how to incorporate these costs into each utility’s 

general rate case. 

* * * * 

Regarding those utilities with deregulated rates, including 

incumbent local exchange carriers (ILECs), we decline to adopt 

any mechanisms for recovery of costs associated with today’s 

rule changes, as telecommunications companies with rate 

flexibility may charge different rates to recover costs without 

 

127 D.00-01-052, 4 CPUC 3d 160, 166 – 168. 

128 The Commission’s general position on its jurisdiction with respect to POUs is 

summarized in Section 3 of today’s decision. 

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our approval. To the extent that a telecommunications 

company with rate flexibility seeks to place a line-item on its 

bill to recover such costs, however, it must not falsely imply 

that such charge is CPUC-mandated or approved. 

* * * * 

Small local exchange carriers which are on cost-of-service 

regulation will operate under the same framework set forth 

above as electric companies. (D.09-08-029 at pp. 43 – 44. 

Emphasis added.) 

We affirm our determination in the Phase 1 Decision that cost-of-service 

utilities are entitled to recover the reasonable costs they incur to comply with the 

regulations that are adopted in this proceeding after the reasonableness of such 

costs has been verified by the Commission. We also affirm that such costs 

should be verified and recovered in general rate case (GRC) proceedings. 

As contemplated by the Phase 1 Decision, we establish interim 

mechanisms, described below, for cost-of-service utilities to recover their 

reasonably incurred and verified costs until such costs can be incorporated into 

each company’s GRC. The interim cost-recovery mechanisms will ensure that 

funding is available in a timely manner to implement the fire-prevention 

measures adopted in this proceeding. 

Consistent with the Phase 1 Decision, we find there is no need to establish 

a cost-recovery mechanism for utilities with deregulated rates. Any utility with 

deregulated rates or rate flexibility that places a line-item charge on its customer 

bills to recover costs that are incurred as a result of this proceeding must not 

state or imply that such charge is mandated or approved by the Commission. 

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6.20.1. Cost Recovery for Electric IOUs 

With certain exceptions described below, the electric IOUs129 shall track 

and record their costs to implement the regulations adopted in this proceeding in 

the Fire Hazard Prevention Memorandum Accounts (FHPMAs) they have 

established pursuant to the Phase 1 Decision. Each electric IOU may file one or 

more applications to recover the costs recorded in its FHPMA. The number and 

timing of applications will be at the discretion of each electric IOU.130 We will 

verify and assess the reasonableness of recorded costs in application 

proceedings. 

The electric IOUs shall record in their FHPMAs only those costs that are 

not being recovered elsewhere. For example, PacifiCorp and Sierra Pacific 

already recover their costs to implement the Phase 1 Decision in their respective 

GRCs.131 Consequently, PacifiCorp and Sierra Pacific may not record any 

Phase 1 costs in their FHPMAs. Similarly, SCE, SDG&E, and SoCalGas have 

included forecasted costs from the Phase 1 Decision in their 2012 GRCs.132 Thus, 

the only Phase 1 costs these companies may record in their FHPMAs are their 

actual costs to implement the Phase 1 Decision that are incurred prior to 2012. 

Each electric IOU may continue to record authorized costs in its FHPMA 

until the first GRC that occurs after the close of this proceeding, at which time 

 

129 For the purpose of today’s decision, the term “electric IOUs” includes Southern 

California Gas Company to the extent it operates overhead power-line facilities that 

are subject to the Commission’s jurisdiction. 

130 An electric IOU may seek to recover the costs recorded in its FHPMA in its next 

scheduled GRC application. 

131 PacifiCorp and Sierra Pacific Joint Phase 2 Opening Brief at 28. 

132 Phase 2 Workshop Report, Appendix B, at B-256, Fn. 66. 

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the FHPMA shall be closed. The electric IOU may then use the GRC mechanism 

to request recovery of the costs it incurs from that point forward to comply with 

the regulations adopted in this rulemaking proceeding. The electric IOU may 

seek to recover the ending balance in its FHPMA, if any, by filing an application. 

6.20.2. Cost Recovery for the Small LECs 

The Small LECs may use their annual California High Cost Fund-A 

(CHCF-A) Tier 3 advice letters133 to request recovery of the costs recorded in 

their FHPMAs. This procedure is consistent with D.91-09-042, which allows 

Small LECs to obtain financial support from CHCF-A based on recorded 

financial data.134 We will verify and assess the reasonableness of the costs 

recorded in each Small LEC’s FHPMA as part of our review the Small LEC’s 

annual CHCF-A advice letters. 

The Small LECs may only seek to recover costs via their CHCF-A advice 

letters that are (1) recorded in their FHPMAs, (2) directly related to the 

implementation of the regulations adopted in this proceeding, and (3) not 

recovered elsewhere. The Small LECs shall provide Commission staff with work 

papers, documents, and/or other information requested by staff to analyze and 

verify the claimed costs. The fact that Small LECs may request recovery of said 

costs does not ensure recovery. The Small LECs may only recover those costs 

that are verified and found reasonable by Commission staff and approved by the 

Commission. 

 

133 The Tier 3 advice letter process allows for protest periods and Commission review of 

the advice letter prior to a final decision or resolution. 

134 D.91-09-042, 41 CPUC 2d 326, 330 – 331. 

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Each Small LEC may continue to use the CHCF-A advice letter process 

until the first GRC that occurs after the close of this proceeding. At that time, the 

Small LEC shall close its FHPMA and thereafter use the GRC mechanism to 

request recovery of the costs it incurs to comply with the regulations adopted in 

this rulemaking proceeding. The Small LEC may seek to recover the ending 

balance it its FHPMA, if any, in its annual CHCF-A advice letter filing. 

We note that there is no requirement for Small LECs to file GRCs. 

However, if a Small LEC does not file a GRC, it will eventually lose all of its 

financial support from the CHCF-A through the so-called waterfall process.135 

Under the waterfall process, a Small LEC will receive 100% of its authorized 

financial support from the CHCF-A for three years following the GRC. Financial 

support then falls to 80% of the authorized amount in the fourth year after the 

GRC, 60% in the fifth year, and zero percent in the sixth year.136 Thus, the ability 

of a Small LEC to recover the costs recorded in its FHPMA through annual 

CHCF-A advice letters will decline and eventually end if it does not file a GRC. 

We will require each Small LEC to close its FHPMA when its authority to 

seek financial support from the CHCF-A reaches zero percent. The company’s 

authority to seek recovery of the costs recorded in its FHPMA shall expire upon 

the closure of its FHPMA. 

 

135 D.91-09-042, 41 CPUC 2d 326, 332. 

136 Ibid. 

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We note that several Small LECs have opted out of the CHCF-A, and there 

is no requirement for these companies to file a GRC.137 These companies may 

seek to recover the costs recorded in their FHPMA as part of their next GRC 

filing, if any. Their authority to seek recovery of such costs will end on 

January 1, 2015, at which time their FHPMAs shall be closed. 

6.21. Implementation 

All entities subject to the rules, regulations, and ordering paragraphs 

adopted by today’s decision shall implement these directives as soon as possible. 

We do not adopt any deadlines except those specifically established in the rules, 

regulations, or ordering paragraphs themselves. 

CPSD shall revise GOs 95, 165, and 166 to incorporate the revisions 

adopted by today’s decision and publish the amended GOs on the Commission’s 

website within 60 days from the issuance date of today’s decision. The adopted 

revisions include replacing the placeholder “Decision 11-XX-YYY” in several 

locations with the decision number for today’s decision. 

7. California Environmental Quality Act 

The California Environmental Quality Act (CEQA)138 applies to any project 

that has a potential for resulting in a direct physical change in the environment 

or a reasonably foreseeable indirect physical change in the environment unless 

the project is exempt from CEQA by statute or regulation.139 The Phase 2 

 

137 These companies are Happy Valley Telephone Company, Hornitos Telephone 

Company, Winterhaven Telephone Company, and Verizon West Coast (which is 

now owned by Frontier). 

138 CEQA is contained in Cal. Pub. Res. Code § 21000 et seq. 

139 14 Cal. Code Regs., Section 15378. 

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Workshop Report states that each proposal addressed by today’s decision is 

exempt from CEQA pursuant to Section 15378 of the CEQA Guidelines140

because it is not a “project” under CEQA and will not have any significant 

impacts on the environment. No party disagrees with this assessment. 

The Commission is the lead agency under CEQA with respect to the 

regulations adopted by today’s decision. We find that all of the adopted 

regulations are exempt from CEQA pursuant to one or more the following 

statutory exemptions or categorical exemptions in the CEQA guidelines: 

• The adopted regulation allows for the operation, repair, or 

maintenance of existing electric utility and CIP facilities, and 

involves negligible or no expansion of an existing authorized 

use. (14 Cal. Code Regs., Section 15301(b).) 

• The adopted regulation allows for the restoration or 

rehabilitation of deteriorated or damaged structures, facilities, 

or mechanical equipment to meet current standards of public 

health and safety, and involves negligible or no expansion of an 

existing authorized use. (14 Cal. Code Regs., Section 15301(d).) 

• The adopted regulation allows for the maintenance of existing 

landscaping and native growth, and involves negligible or no 

expansion of an existing authorized use. (14 Cal. Code Regs., 

Section 15301(h).) 

• The adopted regulation allows for minor alterations of land that 

provide for fuel management activities within 30 feet of 

structures to reduce the volume of flammable vegetation, and 

will not result in the taking of endangered, rare, or threatened 

plant or animal species or significant erosion and sedimentation 

of surface waters. (14 Cal. Code Regs., Section 15304(i).) 

• The adopted regulation involves the creation of government 

funding mechanisms or other government fiscal activities, 

 

140 The CEQA guidelines are set forth in 14 Cal. Code Regs., Section 15000 et seq. 

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which do not involve any commitment to a specific project 

which may result in a potentially significant physical impact 

on the environment. (14 Cal. Code Regs., Section 15378(b)(4).) 

• The adopted regulation involves the establishment, 

modification, structuring, restructuring, or approval of rates or 

other charges for the purpose of (A) meeting operating expenses, 

including employee wage rates and fringe benefits, (B) 

purchasing or leasing supplies, equipment, or materials, 

(C) meeting financial reserve needs and requirements, 

(D) obtaining funds for capital projects necessary to maintain 

service within existing service areas. (Pub. Res. Code 

§ 21080(b)(8).) 

• The adopted regulation will not have a potentially significant 

impact on the environment and is therefore not a “project” as 

defined by CEQA in Pub. Res. Code § 21065 and 14 Cal. Code 

Regs., Section 15378(a). 

• The regulation continues provisions which were adopted in 

D.09-08-029, or which are very similar to those adopted in 

D.09-08-029, wherein it was determined that CEQA did not 

apply to the adopted measures. (D.09-08-029 at 7.) 

8. Proposed Rulemaking Proceeding re: Electric Tariff Rule 20 

8.1. Background 

Electric Tariff Rule 20 provides a process for placing overhead power-line 

facilities underground for aesthetic reasons. The Commission authorizes 

funding and cost recovery for Tariff Rule 20 projects in GRC proceedings.141

Tariff Rule 20 contains a formula for allocating the available funds for 

undergrounding projects among cities and counties. Each jurisdiction saves its 

 

141 D.01-12-009 at 5, Fn. 5. Individual customers may be required to pay a portion of the 

cost to underground electric facilities from the street to the customer’s meter. 

(D.01-12-009 at 5 - 6.) 

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allocation, and can “borrow” ahead for 5 years’ worth of allocations in order to 

fund a project. Because projects are expensive, it may take many years for a 

smaller jurisdiction to afford even a small project. 

Tariff Rule 20 prescribes a multi-stage process for local jurisdictions to 

obtain and use the available funds for undergrounding projects. The governing 

body of the city or county must consult with the electric utility, hold public 

hearings, makes a determination that undergrounding is in the public interest, 

and create an undergrounding district. The project is then designed, scheduled, 

and executed by the IOUs. Projects usually take several years at a minimum. 

The CIPs must place their aerial communication lines underground at the 

same time as the electric utilities. However, unlike the electric IOUs, the CIPs do 

not have a regulatory mechanism to fund their share of undergrounding 

projects. The CIPs must pay for undergrounding projects from general revenues. 

The Phase 2 Scoping Memo determined that Phase 2 “may consider 

adding fire risk to the list of reasons to permit undergrounding under Tariff Rule 

20.142” On February 9, 2010, the CIP Coalition filed a motion to exclude from this 

proceeding any proposed changes to the existing tariff rules governing the 

conversion of aerial facilities to underground facilities. The CIP Coalition argued 

that the proposed changes were subject to Pub. Util. Code § 1708, which requires 

notice before a Commission decision is changed. The CIP Coalition observed 

that no notice had been provided to the parties in prior proceedings where the 

Commission had rejected proposals to revise Tariff Rule 20 to allow aerial 

electric facilities to be placed underground for the purpose of reducing fire risk. 

 

142 Phase 2 Scoping Memo at 8. 

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On April 6, 2010, the assigned ALJ, in consultation with the assigned 

Commissioner, issued a ruling that granted the CIP Coalition’s motion to 

exclude Tariff Rule 20 issues from this proceeding. However, the ruling also 

authorized parties to file comments on whether the Commission should open a 

new rulemaking proceeding to consider if fire risk should be added to the list of 

reasons to permit undergrounding under Tariff Rule 20 and how to provide 

notice of this new proceeding in conformance with Pub. Util. Code § 1708. 

Opening comments were filed on May 7, 2010, by Facilities Management 

Specialists LLC (FMS), SDG&E, TURN, and collectively by the CCTA, Comcast, 

Time Warner, tw telecom, and the Verizon companies.143 Reply comments were 

filed on May 21, 2010, by CPSD, FMS, LADWP, PG&E, SDG&E, and collectively 

by AT&T, CCTA, Comcast, CoxCom, Inc., Cox, Time Warner, tw telecom, and 

the Verizon companies (collectively, “the Commenting CIPs”). 

8.2. Position of the Parties 

CPSD, FMS, LADWP, and SDG&E support a new rulemaking proceeding 

to consider if fire risk should be added to the list of reasons to permit 

undergrounding under Tariff Rule 20. They believe the Commission should 

consider all options for preventing power-line fires. 

SDG&E states that regardless of whether the Commission decides to open 

a new rulemaking proceeding, SDG&E intends to file an application that would 

 

143 The Verizon companies include MCI Communications Services, Inc., d/b/a Verizon 

Business Services (U-5378-C), MCI Metro Access Transmission Services, d/b/a 

Verizon Access Transmission Services (U-5253-C), TTI National, Inc., d/b/a Verizon 

Business Services (U-5403- C), Verizon California Inc. (U-1002-C), and Verizon West 

Coast (U-1020-C). 

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establish a new Tariff Rule 20D for allocating funds among cities and counties to 

place overhead power-line facilities underground for fire-prevention purposes. 

The proposed Tariff Rule 20D would apply only to SDG&E, and not to other 

electric IOUs or CIPs. 

The proposed rulemaking proceeding is opposed by the Commenting CIPs 

and TURN. The Commenting CIPs assert that the Commission must first 

address the issue of CIP cost recovery for undergrounding projects. The 

Commenting CIPs are concerned that a new rulemaking proceeding would 

result in the expansion of undergrounding projects under Tariff Rule 20, 

resulting in greater costs for the CIPs. Unlike the electric IOUs, the CIPs do not 

have captive ratepayers to pay for undergrounding projects. The Commenting 

CIPs argue that the failure to address the issue of CIP cost recovery would raise 

an equal protection challenge, as there is allegedly no rational basis for making 

the electric IOUs whole but not the CIPs. 

TURN states there are several reasons why Tariff Rule 20 is a poor vehicle 

for addressing fire risks. First, Tariff Rule 20 is not designed to address fire risks 

in an urgent manner, as projects usually take several years from conception to 

completion. While this leisurely pace is suitable for beautification projects, it 

may be too slow to address known fire risks. 

Second, the fire risk associated with overhead power-line facilities is 

generally much lower in Northern California. Thus, there is not a statewide need 

to amend Tariff Rule 20 to address fire risk. 

Third, the allocation of funds under Tariff Rule 20 is not appropriate for 

fire-prevention purposes. The majority of funding currently goes to cities. This 

is the opposite of the allocation that would be needed to address fire risk. 

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Finally, the Commission currently requires that aerial communication lines 

be placed underground at the same time that power lines are placed 

underground pursuant to Tariff Rule 20. TURN states there is usually no need to 

place communication lines underground to mitigate fire risks. 

TURN opines that GRCs are a better venue for considering the merits of 

undergrounding projects for fire-prevention purposes. There, the Commission 

can consider the costs and benefits of different measures for mitigating fire risk 

and allocate limited ratepayer funds to the most cost-effective fire-prevention 

measures and the highest priority fire-prevention projects. 

SDG&E agrees with TURN that funding for fire-prevention measures, 

including undergrounding projects, should be decided in GRC proceedings. But 

SDG&E also believes that a new Tariff Rule 20D for fire-safety undergrounding 

could help SDG&E implement Commission-authorized fire safety 

undergrounding activities by making the affected cities and counties an integral 

part of the undergrounding process. This is because the new Tariff Rule 20D 

would (1) provide for greater municipal and public input on selection, 

prioritization, schedules, and cost; (2) allow for better coordination with 

municipalities on issues such as land rights acquisition and public 

improvements; (3) provide an equitable distribution of projects among 

municipalities; and (4) establish rules that do not need to be litigated each GRC. 

PG&E neither supports nor opposes a new rulemaking proceeding to 

consider if fire risk should be added to the list of reasons to permit 

undergrounding under Tariff Rule 20. If the Commission decides to open a new 

proceeding, PG&E urges the Commission to ensure that the entire panoply of 

costs, risks and benefits is fully explored and that all stakeholders are invited. 

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8.3. Discussion 

The overarching purpose of Tariff Rule 20 is to place overhead power lines 

underground for aesthetic reasons. To this end, the tariff rule contains a formula 

for allocating the available funds among cities and counties, and prescribes a 

process that cities and counties must use to obtain funds. 

The purpose of Tariff Rule 20 is unrelated to fire prevention. We see no 

reason to clutter the rule with new and unrelated provisions regarding fire 

prevention. We agree with TURN that GRCs, and not Tariff Rule 20, should be 

used to allocate ratepayer funds for fire-prevention projects. 

The GRC process has several advantages over Tariff Rule 20 in terms of 

allocating funds for fire-prevention purposes. First, a GRC enables the utility, 

the Commission, and interested parties to identify the highest priority 

fire-prevention projects and to allocate ratepayer funds to those projects. In 

contrast, Tariff Rule 20 contains no procedures for identifying high priority 

fire-prevention projects and no mechanism for ensuring that such projects are 

funded. Each city and county would have discretion to use its allotted funds for 

lower priority fire-prevention projects in its own jurisdiction ahead of higher 

priority projects in other jurisdictions. 

Second, the only fire-prevention measure available under Tariff Rule 20 is 

placing overhead power-line facilities underground. This is perhaps the most 

expensive fire-prevention tool available. There are many other fire-prevention 

options, such as line spacers, wire insulation, and vegetation management. A 

GRC proceeding would allow the Commission to consider a range of fireprevention options and select the most cost-effective solutions. 

Finally, fire risk should be assessed from the standpoint of the utility’s 

entire service territory, and not from the piecemeal and narrow geographical 

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perspectives of individual jurisdictions. The utility can assess wind conditions, 

vegetation type, population density, and other factors to identify the portions of 

its service territory where the risk of power-line fires is greatest. While this can 

be done in a GRC proceeding, it is not possible with Tariff Rule 20. 

We conclude for the preceding reasons that there is no need to open a new 

rulemaking proceeding to consider adding fire risk to the list of reasons to 

permit undergrounding under Tariff Rule 20. Our decision to forego a new 

rulemaking proceeding does not signal any reduction in our concern about fire 

prevention. To the contrary, we believe that GRCs are a superior regulatory 

mechanism for selecting and funding fire-prevention measures compared to the 

ad hoc allocation of ratepayer funds for fire-prevention projects under Tariff 

Rule 20.144 

9. Need for Hearing 

In OIR 08-11-005, the Commission preliminarily determined that hearings 

are not needed in this proceeding. Parties were provided an opportunity by the 

Phase 1 Scoping Memo and the Phase 2 Scoping Memo to request evidentiary 

hearings, but no such requests were submitted. Today’s decision affirms that 

there is no need for evidentiary hearings in Phase 2 of this proceeding. 

10. Comments on the Proposed Decision 

The proposed decision for Phase 2 of this proceeding was mailed to the 

parties in accordance with Pub. Util. Code § 311, and comments were allowed in 

 

144 Today’s decision does not prejudge any application that SDG&E may file for 

authority to establish a new Tariff Rule 20D to allocate funds for undergrounding 

power lines for fire-prevention purposes, much like Tariff Rule 20 allocates funds for 

beautification projects. 

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accordance with Rule 14.3 of the Commission’s Rules of Practice and Procedure. 

Comments were filed on June 30, 2011 by CFBF; CAISO; jointly by CCTA, 

Comcast, and Time Warner; the CIP Coalition; CMUA; Cox; CPSD; DRA; FMS; 

LA County; LADWP; MGRA; PacifiCorp; PG&E; SDG&E, SCE; the Small LECs; 

and TURN. Reply comments were filed on July 8, 2011, by AT&T; Cal Fire; 

CFBF; jointly by CCTA, Comcast, Cox, and Time Warner; the CIP Coalition; 

CMUA; CPSD; LA County; MGRA; PG&E; SDG&E; SCE; and TURN. The 

comments and reply comments have been reflected, as appropriate, in the final 

decision adopted by the Commission. 

11. Assignment of the Proceeding 

Timothy A. Simon is the assigned Commissioner and Timothy Kenney is 

the assigned Administrative Law Judge in this proceeding. 

Findings of Fact 

1. The regulatory requirements adopted by today’s decision will improve 

the fire safety of overhead electric utility facilities and aerial CIP facilities in close 

proximity to overhead power lines. Any additional costs that the new regulatory 

requirements impose on electric utilities, CIPs, and other entities are more than 

offset by the public-safety benefits. 

2. In addition to enhancing fire safety, many of the revisions to GO 95 and 

GO 165 that are adopted by today’s decision will (i) improve the clarity of these 

General Orders, (ii) streamline existing requirements, and/or (iii) remove 

obsolete, unnecessary, or redundant provisions in these General Orders. These 

revisions will improve the ability of CIPs and electric utilities to manage their 

operations efficiently and thereby reduce safety hazards and costs. 

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3. There is a grave and ongoing risk that Santa Ana windstorms will cause 

catastrophic power-line fires unless electric utilities in Southern California plan 

and prepare for such events. 

4. The FRAP Map and Reax Map show there are millions of acres in 

Northern California where there is a high fire threat. However, the magnitude of 

the risk of catastrophic wind-caused power-line fires occurring in Northern 

California is unknown at this time. 

5. Today’s decision makes no findings or conclusions regarding the root 

cause of the Guejito Fire in October 2007. 

6. If not installed and maintained properly, aerial CIP facilities located in 

close proximity to power lines could contact power lines and ignite a fire. 

CIP-only poles can also fail if not installed and maintained properly, causing a 

cascade that topples nearby joint-use poles, resulting in a wildfire. 

7. The protection of public safety requires that CIPs carry out patrol 

inspections, detailed inspections, and intrusive inspections of their aerial 

facilities and poles located in close proximity to overhead power-line facilities in 

the high fire-threat areas of the state. 

8. There is no history of catastrophic power-line fires in Northern 

California, and Northern California does not experience Santa Ana windstorms 

that contribute significantly to the risk of catastrophic power-line fires in 

Southern California. Because the risk of power-line fires is lower in Northern 

California compared to Southern California, it is reasonable to have a lower 

frequency of patrol inspections, detailed inspections, and intrusive inspections of 

CIP facilities in Northern California compared to Southern California. 

9. The failure to keep power lines clear of vegetation poses a serious threat 

to service reliability and public safety. In order to maintain service reliability 

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and to protect public safety, electric utilities need appropriate tools to deal with 

customers who prevent access to their property for vegetation management. 

10. The minimum time-of-trim guidelines in Appendix E of GO 95 provide 

an adequate margin for fire safety in most circumstances. Electric utilities and 

CIPs are authorized by Appendix E to exceed the minimum time-of-trim 

guidelines when it is advantageous to do so for fire-safety and service reliability 

purposes. 

11. Appendix E of GO 95 does not provide guidance about what factors 

should be considered by electric utilities and CIPs for determining whether, and 

to what extent, they should exceed the minimum time-of-trim guidelines 

specified in Appendix E. 

12. It is of utmost importance to perform pole-loading calculations and to 

share information needed for pole-loading calculations in order to ensure that 

utility poles do not become overloaded and fail, which could ignite a fire, injure 

and kill people, and destroy property. 

13. Wood products have considerable natural variability. As a result, the 

actual strength of wood products used by electric utilities and CIPs to build 

structures will likely deviate to some degree from the presumed strength of 

materials listed in Rules 48.1 though 48.7 of GO 95. 

14. The current Heavy Loading District and Light Loading District in 

Rule 43, and the associated loading standards for electric utility and CIP facilities 

in each district, are not specifically intended to mitigate the elevated risk of 

power-line fires occurring and spreading rapidly in high fire-threat areas. 

15. Marking CIP cables and conductors attached to joint-use poles with 

ownership information will enhance fire safety by enabling electric utilities, CIPs, 

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and others to identify the owner of CIP facilities that pose a fire hazard so that 

the owner can be notified and repairs made. 

16. There are many power-line fires every year. Requiring electric IOUs to 

report information on power-line fires would be useful in formulating 

fire-prevention measures and gauging the effectiveness of the adopted measures. 

17. The availability of high-resolution maps that can accurately identify 

areas where power-line fires are more likely to occur and spread rapidly is 

essential to the successful and cost-effective deployment of many of the 

fire-prevention measures adopted in this proceeding. 

18. The FRAP Map is not suited for use on a permanent basis to designate 

areas where the fire-preventions measures adopted in this proceeding should be 

deployed. 

19. The Reax Map and the SDG&E Map are designed to identify areas 

where fire-prevention measures should be deployed, but neither map has been 

reviewed by neutral experts. 

20. With the possible exception of SDG&E’s service territory, there are 

currently no maps that accurately identify areas of Southern California where 

power-line fires are more likely to occur and spread rapidly. 

21. There were no requests for evidentiary hearings in Phase 1 or Phase 2 of 

this proceeding. 

Conclusions of Law 

1. This is a quasi-legislative rulemaking proceeding in which no party 

requested evidentiary hearings and none were held. Accordingly, today’s 

decision may rely on legislative facts obtained from written submissions in this 

proceeding, such as the Phase 2 Workshop Report and briefs. Today’s decision 

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may also draw on evidence from past proceedings, the Commission’s experience 

and expertise in regulating utilities, Commission policies, and common sense. 

2. Without determining the root cause of any of the October 2007 wildfires, 

several potential issues involving the overhead facilities of electric utilities and 

CIPs have been identified that, in an abundance of caution, warrant adoption of 

new regulations to reduce the risk of wildfires. 

3. It is in the public interest to adopt the revisions to GOs 95, 165, and 166 

that are contained in Appendix B of today’s decision for the reasons set forth in 

the body of today’s decision and the Findings of Fact. 

4. CPSD should amend GOs 95, 165, and 166 to incorporate the revisions to 

these GOs adopted by today’s decision and publish the amended GOs on the 

Commission’s website within 60 days from today’s decision. The adopted 

revisions include replacing the placeholder “Decision 11-XX-YYY” in several 

locations with the decision number for today’s decision. 

5. The deadlines for completing corrective actions under the inspection and 

maintenance programs established by electric utilities pursuant to GO 165 may 

not exceed the deadlines for completing corrective actions specified in Rule 18A 

of GO 95, as modified by today’s decision. 

6. Each electric IOU in Southern California should prepare and submit a 

fire-prevention plan by December 31, 2012. 

7. Each electric IOU in Northern California should determine if there is a 

credible risk of catastrophic power-line fires in its service territory and, if so, 

prepare and submit a fire-prevention plan by December 31, 2012. 

8. Each electric IOU’s fire-prevention plan should address situations where 

all three of the following conditions occur simultaneously: (i) 3-second wind 

gusts exceed the structural and mechanical design standards for overhead 

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power-line facilities; (ii) these 3-second gusts occur during a period of high fire 

danger; and (iii) the affected facilities are located in high fire-threat areas. The 

fire-prevention plans should also specify (a) how the utility will identify the 

occurrence of 3-second gusts that exceed the design standards for overhead 

power-line facilities; and (b) the countermeasures the utility will implement to 

mitigate the threat of power-line fire ignitions. 

9. Any electric IOU that intends to shut off power as part of its fireprevention plan should file an application for authority to do so. The application 

should demonstrate with a cost-benefit analysis developed in accordance with 

the guidance provided by D.09-09-030 that the benefits of shutting off power in 

terms of a net reduction in fires outweigh the substantial costs, burdens, and 

risks that shutting off power would impose on customers and communities 

affected by the shut off. 

10. The new Standard 1.E of GO 166 that is adopted by today’s decision is 

subject to the other provisions in GO 166, including the requirement to update a 

fire-prevention plan annually and to conduct an annual exercise of the 

fire-prevention plan. 

11. The Commission has authority to determine what constitutes compliance 

with GO 95 on a case-by-case basis in light of specific facts and circumstances. 

12. For the purpose of implementing the patrol and detailed inspection 

intervals for CIP facilities in GO 95, Rule 80.1, and for electric utility facilities in 

GO 165, the term “year” should be defined as 12 consecutive calendar months 

starting the first full calendar month after an inspection is performed, plus or 

minus two calendar months, not to exceed the end of the calendar year in which 

the next inspection is due. 

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13. Electric IOUs should revise their tariffs to state that the electric utility may 

shut off power to customers who do not allow access to their property for 

vegetation-management activities. The authority to shut off power should be 

limited to situations where there is a breach of the minimum vegetation 

clearances required by GO 95, Rule 35, Table 1, Cases 13 and 14. 

14. Electric utilities have wide latitude under Appendix E of GO 95 to exceed 

the minimum time-of-trim guidelines for fire-safety and service reliability 

purposes. 

15. The failure to maintain the required minimum clearance between an 

energized conductor and another conductor is either a Level 1 or Level 2 

nonconformance, depending on circumstances, and must be corrected within the 

timeframes specified in Rule 18 of GO 95. 

16. The definition of what constitutes a material increase in load on a utility 

structure that is contained in Ordering Paragraph 4 of D.09-08-029 is reasonable 

and should be incorporated into Rule 44.2 of GO 95. 

17. A new Phase 3 of this proceeding with facilitated workshops should be 

instituted to consider, develop, and adopt regulations regarding the matters 

identified in the body of today’s decision. 

18. The threat of catastrophic power-line fires is so great that the public 

interest is better served by requiring CIPs and electric utilities to implement the 

fire-prevention measures adopted in this proceeding using the available 

fire-threat maps rather than waiting for the development and adoption of 

permanent fire-threat maps in Phase 3. 

19. Until permanent fire-threat maps are adopted in Phase 3, the CIPs and 

electric utilities should use the FRAP Map, Reax Map, and SDG&E Map on an 

interim basis to implement the fire-prevention measures adopted in this 

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proceeding. The CIPs should use Reax Map in Northern California and the 

FRAP Map in Southern California. The electric utilities other than SDG&E 

should use the Reax Map in Northern California and the FRAP Map in Southern 

California. SDG&E should use its own fire-threat map or the FRAP Map. 

20. Electric utilities and CIPs should create and retain records of all 

pole-loading calculations, patrol inspections, detailed inspections, and repairs for 

at least ten years in order to provide information needed for forensic analysis in 

the event there is a major safety-related incident associated with overhead 

facilities. For the same reason, electric utilities and CIPs should create and retain 

records of all intrusive inspections of a wood utility pole, and any associated 

repairs that result from such inspections, for the life of the pole. This new 

record-retention requirement should apply to records currently in a company’s 

possession and records created on or after the date of today’s decision. 

21. Cost-of-service utilities are entitled to recover the reasonable costs they 

incur to implement the regulations that are adopted in this proceeding after the 

reasonableness of such costs has been verified by the Commission. The cost-ofservice utilities should be authorized to seek recovery of such costs on an interim 

basis until such costs can be incorporated into each utility’s GRC. 

22. There is no need to establish a cost-recovery mechanism for utilities and 

CIPs whose rates are not regulated by the Commission. 

23. All entities subject to the rules, regulations, and ordering paragraphs 

adopted by today’s decision should implement these directives as soon as 

possible. There should be no implementation deadlines except for those 

specifically established in the rules, regulations, or ordering paragraphs 

themselves. 

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24. CEQA applies to any project that has a potential for resulting in either a 

direct physical change in the environment or a reasonably foreseeable indirect 

physical change in the environment unless the project is exempt from CEQA by 

statute or regulation. 

25. The Commission is the lead agency under CEQA with respect to the 

regulations adopted by today’s decision. 

26. All of the regulations adopted by today’s decision are exempt from CEQA 

pursuant to one or more the statutory exemptions or categorical exemptions 

identified in the body of today’s decision. 

27. GRCs are a superior regulatory mechanism for selecting and funding 

fire-prevention measures compared to the ad hoc allocation of ratepayer funds 

for fire-prevention projects under Electric Tariff Rule 20. 

28. There is no need for evidentiary hearings in Phase 2 of this proceeding. 

29. The following order should be effective immediately. 

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ORDER

IT IS ORDERED that: 

1. General Orders (GOs) 95, 165, and 166 are revised to include the new and 

amended rules set forth in Appendix B of today’s decision. The Commission’s 

Consumer Protection and Safety Division shall revise GOs 95, 165, and 166 to 

incorporate the new and amended rules and publish the revised GOs on the 

Commission’s website within 60 days from the issuance date of today’s decision. 

2. Each investor-owned electric utility in Southern California shall (i) prepare 

a fire-prevention plan, and (ii) file and serve a copy of its fire-prevention plan by 

December 31, 2012, via a Tier 1 compliance advice letter. 

3. Each investor-owned electric utility in Northern California shall take the 

following steps to determine the risk of catastrophic power-line fires in its 

service territory and prepare a fire-prevention plan, if necessary: 

i. Identify its overhead power-line facilities that are located in high 

fire-threat areas on the fire-threat maps adopted by today’s decision. 

ii. Make a good-faith effort to obtain historical records of Red Flag 

Warnings issued by the National Weather Service that applied to 

areas occupied by facilities identified in the previous Item (i). 

iii. Make a good-faith effort to obtain historical wind records of Remote 

Automatic Weather Stations located within 25 miles of the facilities 

identified in Item (i). 

iv. Use the information from Items (ii) and (iii) to estimate how often, if 

ever, 3-second wind gusts occur during a Red Flag Warning that 

exceed the maximum working stress specified in General Order 95, 

Section IV, for facilities identified in Item (i). 

v. Develop a fire-prevention plan if the utility determines, after 

completing the previously identified tasks, that it has overhead 

power-line facilities in a high fire-threat area where it is reasonably 

foreseeable that the probability of 3-second wind gusts exceeding the 

maximum working stresses for such facilities during a Red Flag 

Warning is 3% or more during a 50-year period. 

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vi. File a Tier 1 compliance advice letter by December 31, 2012 that either 

(a) contains a copy of the fire-prevention plan, or (b) provides notice 

that a fire-prevention plan is not required by today’s decision. 

4. The fire-prevention plans required by today’s decision shall address 

situations where all three of the following conditions occur simultaneously: 

(i) 3-second wind gusts exceed the structural or mechanical design standards for 

the affected overhead power-line facilities, (ii) these 3-second gusts occur during 

a period of high fire danger, and (iii) the affected facilities are located in a high 

fire-threat area. For the purpose of this Ordering Paragraph, the following 

definitions apply: (a) structural and mechanical design standards are the 

maximum working stresses set forth in Section IV of General Order 95; (b) period 

of high fire danger is the period covered by a Red Flag Warning issued by the 

United States National Weather Service; and (c) high fire-threat areas are areas 

designated as such on the fire-threat maps adopted by today’s decision. 

5. The fire-prevention plans required by today’s decision shall specify (i) how 

the investor-owned electric utility will identify the occurrence of 3-second wind 

gusts that exceed the structural or mechanical design standards for overhead 

power-line facilities; and (ii) the countermeasures the utility will implement to 

mitigate the threat of power-line fire ignitions. 

6. Any investor-owned electric utility that intends to shut off power as part of 

its fire-prevention plan must file an application for authority to do so. The 

application shall demonstrate with a cost-benefit analysis developed in 

accordance with the guidance provided by Decision 09-09-030 that the benefits of 

shutting off power in terms of a net reduction in fires outweigh the substantial 

costs, burdens, and risks that shutting off power would impose on customers 

and communities affected by the shut off. The application must also identify 

proposed mitigation measures to reduce or eliminate the inevitable adverse 

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impacts caused by shutting off power, particularly the adverse impacts on 

people with disabilities, providers of essential services, and schools. 

7. Investor-owned electric utilities shall file and serve a Tier 3 advice letter to 

revise their tariffs to state that the electric utility may shut off power to 

customers who do not allow access to their property for vegetation management 

activities, subject to the following conditions: 

i. The authority to shut off power is limited to situations where there is 

a breach of the minimum vegetation clearances for power lines 

required by General Order (GO) 95, Rule 35, Table 1, Cases 13 and 14. 

ii. The authority to shut off power to customers who obstruct vegetation 

management activities does not extend to customers that are state 

and local governments and agencies. 

iii. The authority to shut off power is limited to one meter serving the 

property owner’s primary residence, or if the property owner is a 

business entity, the entity’s primary place of business. This one meter 

is in addition to shutting off power, if necessary for public safety, at 

the location of the vegetation-related fire hazard. 

iv. Prior to shutting off power, the electric utility shall follow the thencurrent procedures and notice requirements applicable to 

discontinuance of service for non-payment, including the 

requirements applicable for sensitive customers, customers who are 

not proficient in English, multifamily accommodations, and other 

customer groups, except as set forth in Item v below. To the extent 

practical, the applicable procedures and notice requirements shall be 

completed prior to a breach of the minimum vegetation clearances 

required by GO 95, Rule 35, Table 1, Cases 13 and 14. 

v. For vegetation hazards that pose an immediate threat to public safety, 

the electric utility may shut off power to the obstructing property 

owner’s residence or primary place of business at any time without 

prior notice, except when the customer receives service under a 

medical baseline allowance. If power is shut off without prior notice, 

the electric utility shall attempt to contact the property owner for five 

consecutive business days by daily visits to the property owner’s 

residence or primary place of business, in addition to sending a 

written notice, to inform the property owner why power has been 

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shut off and how to restore service. If a utility determines that it is 

necessary to shut off power to a medical baseline customer, the utility 

shall attempt to notify the customer by telephone prior to the shut off. 

8. Phase 3 of this proceeding is instituted to consider, develop, and adopt 

regulations regarding the following matters: 

i. Revising Section IV of General Order (GO) 95 to reflect modern 

materials and practices, with the goal of improving fire safety. 

ii. Revising Section IV of GO 95 to incorporate standards regarding 

wood structures and materials that (a) provide electric utilities and 

communications infrastructure providers (CIPs) with clear guidance 

for reliably obtaining prescribed safety factors when using wood 

products with inherent variability, and (b) can be enforced by the 

Commission and the Commission’s Consumer Protection and Safety 

Division (CPSD). 

iii. Revising Section IV of GO 95 to incorporate (a) a new High 

Fire-Threat District, (b) one or more maps of the High Fire-Threat 

District, and (c) fire-safety standards for the design and construction 

electric utility and CIP structures in the High Fire-Threat District. 

iv. Assessing whether any of the new fire-safety standards developed 

pursuant to the previous Item iii(c) should apply to existing facilities 

in the High Fire-Threat District in light of cost-benefit considerations 

and Rule 12 of GO 95 and, if so, developing a plan, timeline, and cost 

estimate for upgrading existing facilities in the High Fire-Threat 

District to meet the new standards. 

v. Requiring investor-owned electric utilities (IOUs) to report data to 

CPSD regarding power-line fires and requiring CPSD to use such 

data to (a) identify and assess systemic fire-safety risks associated 

with overhead power-line facilities and aerial communications 

facilities in close proximity to power lines, and (b) formulate 

cost-effective measures to reduce systemic fire risks. The requirement 

shall be developed in consultation with the IOUs, CIPs, the Mussey 

Grade Road Alliance, California Department of Forestry and Fire 

Protection (Cal Fire), and other interested parties in this proceeding. 

vi. Preparing a detailed work plan for the development, adoption, 

implementation, and funding of fire-threat maps that accurately 

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line fires occurring. Once adopted, these maps shall be used in 

conjunction with the fire-prevention measures adopted by 

Decision 09-08-029 and today’s decision that rely on fire-threat maps 

for their implementation. The IOUs and CIPs shall cooperate with 

CPSD and Cal Fire in the preparation of the work plan. The other 

parties in this proceeding and the Lawrence Livermore National 

Laboratory (LLNL) are invited to participate. The work plan shall 

contain the following: 

a. A detailed proposal for the development of high resolution 

fire-threat maps that cover the entire state. The detailed proposal 

shall address the option of reviewing and adopting for regional 

or statewide use the Reax Map and/or the fire-threat map 

developed by San Diego Gas & Electric Company (SDG&E). 

b. Recommendations for obtaining assistance from Cal Fire, 

LLNL, and other neutral experts in the development and 

review of fire-threat maps, including the Reax Map and the 

SDG&E Map. 

c. Estimated costs for the development, expert review, 

implementation, and maintenance of fire-threat maps. 

d. Recommendations for funding the development, expert 

review, implementation, and maintenance of fire-threat 

maps. 

e. A proposed schedule and milestones for the development, 

adoption, and implementation of fire-threat maps. 

f. The work plan may include alternative proposals and 

recommendations if the workshop participants cannot 

reach a consensus. 

9. Facilitated workshops shall be held in Phase 3 regarding the matters 

identified in the previous Ordering Paragraph. The Assigned Commissioner 

and/or the assigned Administrative Law Judge may appoint a neutral facilitator 

for the Phase 3 workshops. 

10. The assigned Commissioner shall convene a prehearing conference (PHC) 

for Phase 3 and set a schedule for parties to file written comments prior to the 

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PHC regarding the scope of Phase 3. These comments may include proposals to 

add and/or delete issues from Phase 3. 

11. Today’s decision constitutes a preliminary scoping memo for Phase 3 

and, as such, sets a preliminary deadline of 18 months from the issuance date of 

today’s decision for resolving Phase 3 issues pursuant to Pub. Util. Code 

§ 1701.5(b). The final deadline will be set forth in the Assigned Commissioner’s 

scoping memo for Phase 3. The exact scope and schedule for Phase 3, and the 

process and procedures for conducting Phase 3, shall be set forth in the assigned 

Commissioner’s scoping memo for Phase 3. 

12. Until permanent fire-threat maps are adopted in Phase 3, the electric 

utilities and communication infrastructure providers (CIPs) shall use the 

following fire-threat maps to implement the fire-prevention measures adopted 

by Decision (D.) 09-08-029 and today’s decision that rely on a fire-threat map for 

their implementation: 

i. The CIPs and electric utilities other than San Diego Gas & Electric 

Company (SDG&E) shall use the Reax Map for Northern California 

and Cal Fire’s Fire Resource Assessment Program Fire Threat Map 

(FRAP Map) in Southern California. SDG&E may use its own 

fire-threat map. Copies of the Reax Map and FRAP Map are 

contained in Appendix C of today’s decision. 

ii. The fire-prevention measures adopted by D.09-08-029 and today’s 

decision shall be implemented on an interim basis in areas that are 

designated as Extreme and Very High Fire Threat Zones on the 

FRAP Map and the SDG&E Map, and in areas that are designated as 

Threat Class 3 and Threat Class 4 on the Reax Map. The FRAP Map, 

SDG&E Map, and Reax Map shall be used to establish the 

approximate boundaries for the implementation of the fireprevention measures adopted by D.09-08-029 and today’s decision. 

The boundaries are to be broadly construed. The CIPs and electric 

utilities shall use their own expertise and judgment to determine if 

local conditions require them to adjust the boundaries of the relevant 

map. 

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iii. SDG&E shall make its fire-threat map available to any party that 

requests it. The CIPs shall make the Reax Map available to other 

parties for the purposes set forth in today’s decision. 

13. Any utility with deregulated rates or rate flexibility that seeks to place a 

line-item charge on its customer bills to recover costs that are incurred as a result 

of this proceeding must not state or imply that the line-item charge is mandated 

or approved by the Commission. 

14. The electric investor-owned utilities (IOUs) and Small Local Exchange 

Carriers (LECs) shall use the following procedures to request the recovery of the 

costs they incur to implement the regulations adopted in this proceeding: 

i. The electric IOUs and Small LECs may only seek to recover costs that 

are recorded in the Fire Hazard Prevention Memorandum Accounts 

(FHPMAs) they have established pursuant to Decision 09-08-029. 

Companies shall record in their FHPMAs only those costs that are not 

being recovered elsewhere. For the purpose of today’s decision, the 

term “electric IOUs” includes Southern California Gas Company to 

the extent it operates overhead power-line facilities that are subject to 

the Commission’s jurisdiction. 

ii. Each electric IOU may file one or more applications to request the 

recovery of the costs recorded in its FHPMA. The number and timing 

of applications will be at the discretion of the electric IOU. Each 

electric IOU may continue to use this procedure until the first general 

rate case (GRC) that occurs after the close of this proceeding. At that 

time, the electric IOU shall close its FHPMA and thereafter use the 

GRC mechanism to request recovery of the costs it incurs to comply 

with the regulations adopted in this proceeding. The electric IOU 

may seek to recover the ending balance in its FHPMA, if any, by 

filing an application. 

iii. Each Small LEC may use its annual California High Cost Fund-A 

(CHCF-A) Tier 3 advice letter to request the recovery of costs 

recorded in its FHPMA. Each Small LEC may continue to use this 

procedure until the first GRC that occurs after the close of this 

proceeding. At that time, the Small LEC shall close its FHPMA and 

thereafter use the GRC mechanism to request recovery of the costs it 

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incurs to comply with the regulations adopted in this proceeding. 

The Small LEC may seek to recover the ending balance in its FHPMA, 

if any, in its annual CHCF-A advice letter filing. 

iv. A Small LEC shall close its FHPMA when its authority to seek 

financial support from the CHCF-A reaches 0%. The company’s 

authority to seek recovery of any costs remaining in its FHPMA will 

expire upon the closure of its FHPMA. 

v. The Small LECs that have opted out of the CHCF-A may seek to 

recover the costs recorded in their FHPMAs as part of their next GRC 

filing, if any. Their authority to seek recovery of such costs will end 

on January 1, 2015, at which time their FHPMAs shall be closed. 

15. All entities subject to the rules, regulations, and ordering paragraphs 

adopted by today’s decision shall implement these directives as soon as possible. 

Today’s decision does not adopt any deadlines except those specifically 

established in the rules, regulations, or ordering paragraphs themselves. 

16. For the purpose of the previous ordering paragraphs, Southern California 

is defined as Imperial, Los Angeles, Orange, Riverside, Santa Barbara, 

San Bernardino, San Diego, and Ventura Counties. Northern California is 

defined as all other counties in California. 

17. This proceeding remains open for Phase 3. 

This order is effective today. 

Dated January 12, 2012, at San Francisco, California. 

MICHAEL R. PEEVEY 

 President 

TIMOTHY ALAN SIMON 

MICHEL PETER FLORIO 

CATHERINE J.K. SANDOVAL 

MARK J. FERRON 

 Commissioners 

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Appendix A: Proposed Regulations 

Appendix A shows the proposed revisions and additions to 

General Orders 95 and 165 with strikeout and underline. 

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Consensus Proposal 1 re: GO 95, Rule 18A

Proposed Revisions to Current Rule 18A Shown with Strikeout and Underline 

18 Reporting and Resolution of Safety Hazards Discovered by Utilities 

A. Resolution of Safety Hazards And General Order 95 Nonconformances 

Violations

Each company (including utilities and CIPs) is responsible for taking appropriate 

corrective action to remedy safety hazards and GO 95 nonconformances 

violations posed by their facility. Upon completion of the corrective action, the 

company records shall show the nature of the work, the date and identity of 

persons performing the work. Prior to the work being completed, the company 

shall document the current status of the safety hazard, including whether the 

safety hazard is located in an Extreme and Very High Fire Threat Zone in 

Southern California, and shall include a scheduled date of corrective action. 

These records shall be preserved by the company for at least five years, and shall 

be of sufficient detail to allow Commission staff during an audit, if any, to 

determine that the safety hazard has been remedied. The records shall be made 

available to Commission staff immediately upon request. Additionally, for any 

work completed after the initial scheduled date of corrective action, the company 

shall document the reason or reasons that the work was not completed by the 

original scheduled date of corrective action. 

For purposes of this rule, “safety hazard” means a condition that poses a 

significant threat to life or property, including, but not limited to, the ignition of 

a wildland or structure fire. “Extreme and Very High Fire Threat Zones” are 

defined in the Commission decision issued in Phase I of R.08-11-005. “Southern 

California” is defined as the following: Santa Barbara, Ventura, San Bernardino, 

Riverside, Los Angeles, Orange, and San Diego Counties. 

Companies that have existing General Order 165 auditable inspection and 

maintenance programs that are consistent with the purpose of Rule 18 shall 

continue to follow their General Order 165 programs. All companies shall 

establish an auditable maintenance program for their facilities and lines. 

Further, all companies must include a timeline for corrective actions to be taken 

following the identification of a safety hazard or nonconformance violation of 

General Orders 95 or 128 on the companies’ facilities. 

The auditable maintenance program should be developed and implemented 

based on the following principles. 

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(1) Priorities shall be assigned based on the specifics of the safety hazard or 

nonconformance violation as related to direct impact and the probability for 

impact on safety or reliability using the following factors: 

• Type of facility or equipment; 

• Location; 

• Accessibility; 

• Climate; 

• Direct or potential impact on operations, customers, electrical company 

workers, communications workers, and the general public; 

• Whether the safety hazard or nonconformance violation is located in an 

Extreme or Very High Fire Threat zone. 

(2) There will be three priority levels, as follows: 

(a) Level 1: 

o Immediate safety and/or reliability risk with high probability for 

significant impact. 

o Take action immediately, either by fully repairing the condition, or by 

temporarily repairing and reclassifying the condition to a lower 

priority. 

 (b) Level 2: 

o Variable (non-immediate high to low) safety and/or reliability risk. 

o Take action to correct within specified time period (fully repair, or by 

temporarily repairing and reclassifying the condition to a lower 

priority). 

o Time period for correction to be determined at the point of 

identification by a qualified company representative: 

Overhead: 0-59 months 

o Where communications company actions result in electric utility GO 

nonconformances violations, the electric utility’s remedial action will be 

to transmit a single documented notice of identified nonconformances 

violations to the communications company for compliance. 

(c) Level 3: 

o Acceptable safety and/or reliability risk. 

o Take action (re-inspect, re-evaluate, or repair) at or before the next 

detailed inspection. 

(d) Exceptions (Levels 2 and 3 only) – Correction times may be extended 

under reasonable circumstances, such as: 

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o Third party refusal 

o Customer issue 

o No access 

o Permits required 

o System emergencies (e.g. fires, severe weather conditions) 

(3) Upon completion of the corrective action, the company’s records shall show 

the nature of the work, the date, and the identity of persons performing the 

work. These records should be preserved by the company for at least five years. 

(4) The company shall prioritize implementing this maintenance plan within the 

Extreme and Very High Fire Threat Zones of Southern California. With the 

exception of a safety hazard or nonconformance violation requiring immediate 

correction, a company must correct a nonconformance violation or safety hazard 

within 30 days of discovering or being notified of a nonconformance violation or 

safety hazard, if the nonconformance violation or safety hazard fails to fully 

comply with violates a clearance requirement listed in columns E, F, or G of 

Table 1 in this General Order, or violates a pole overloading requirement in Rule 

44.3 of this General Order, and is located in an Extreme and Very High Fire 

Threat Zone in Southern California. The company must correct a 

nonconformance violation or safety hazard within 30 days if the utility is notified 

that the nonconformance violation must be corrected to alleviate a significant 

safety risk to any utility’s employees. 

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Consensus Proposal 2 re: GO 95, Rule 18B 

Proposed Revisions to Current Rule 18B Shown with Strikeout and Underline 

B. Notification of Safety Hazards 

If a company, while performing inspections of inspecting its facilities, discovers a 

safety hazard(s) on or near a communications facility, or transmission or 

distribution electric facility involving another company, the inspecting company 

shall notify the other company and/or facility owner of such safety hazard(s) no 

later than 10 business days after the discovery. The inspecting company shall 

also provide a copy of the notice to the pole owner(s). The inspecting company 

shall include in such notice whether the safety hazard which requires corrective 

action is located in a designated Extreme and Very High Fire Threat Zone in 

Southern California. To the extent the inspecting company cannot determine the 

facility owner/operator of other company, it shall contact the pole owner(s), who 

shall be responsible for promptly notifying the company owning/operating the 

facility with the safety hazard(s), normally not to exceed five business days after 

being notified of the safety hazard. The notification shall be in writing

documented and such documentation must be preserved by all parties for at 

least five years. It is the responsibility of each pole owner to know the identity of 

each entity using or maintaining equipment on its pole.

Note: Each pole owner must be able to determine all other pole owners on poles 

it owns. Each pole owner must be able to determine all authorized entities that 

attach equipment on its portion of a pole.

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Consensus Proposal 3 re: GO 95, Rule 35

Proposed Revisions to Current Rule 35 Shown with Strikeout and Underline 

Where overhead conductors traverse trees and vegetation, safety and reliability 

of service demand that certain vegetation management activities be performed in 

order to establish necessary and reasonable clearances. The minimum clearances 

set forth in Table 1, Cases 13 and 14, measured between line conductors and 

vegetation under normal conditions shall be maintained. (Also see Appendix E 

for tree trimming guidelines.) These requirements apply to all overhead 

electrical supply and communication facilities that are covered by this Order, 

including facilities on lands owned and maintained by California state and local 

agencies.

When a utility supply or communication company has actual knowledge, 

obtained either through normal operating practices or notification to the utility 

company, of that dead, rotten or and diseased trees or dead, rotten or and

diseased portions there of otherwise healthy trees that overhang or lean toward

and may fall into a span of nearby supply or communication lines, said trees or 

portions thereof should be removed. 

Communication and electric supply circuits, energized at 750 volts or less, 

including their service drops, should be kept clear of vegetation in new 

construction and when circuits are reconstructed or repaired, whenever 

practicable. When a utility supply or communication company has actual 

knowledge, obtained either through normal operating practices or notification to 

the utility company, that any its circuit energized at 750 volts or less shows strain 

or evidences abrasion from vegetation contact, the condition shall be corrected 

by reducing conductor tension, rearranging or replacing the conductor, pruning 

the vegetation, or placing mechanical protection on the conductor(s). For the 

purpose of this rule, abrasion is defined as damage to the insulation resulting 

from the friction between the vegetation and conductor. Scuffing or polishing of 

the insulation or covering is not considered abrasion. Strain is present when

deflection causes additional tension beyond the allowable tension of the span

vegetation contact significantly compromises the structural integrity of supply or 

communication facilities. Contact between vegetation and conductors, in and of 

itself, does not constitute a violation of the rule. 

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Consensus Proposal 4 re: GO 95, Rule 37, Table 1, Case 14 

and Footnotes (fff) – (jjj) 

Proposed Revisions to Current Rule Shown with Strikeout and Underline 

Table 1: Basic Minimum Allowable Vertical Clearance of Wires above Railroads, Thoroughfares, Ground or 

Water Surfaces; Also Clearances from Poles, Buildings, Structures or Other Objects (nn) (Letter 

References Denote Modifications of Minimum Clearances as Referred to in Notes Following This 

Table)

 Wire of Conductor Concerned 

Case 

No. 

Nature of 

Clearance 

A 

Span Wires 

(Other than 

Trolley 

Span 

Wires) 

Overhead 

Guys and 

Messenger

s 

B 

Communication

s Conductors 

(including Open 

Wire, Cables and 

Service Drops) 

Supply Service 

Drops of 0-750 

Volts 

C 

Trolley 

Contact 

Feeder 

and 

Span 

Wires, 

0-5,000 

Volts 

D 

Supply 

Conductors 

of 0-750 

Volts and 

Supply 

Cable 

Treated as 

in Rule 

57.8 

E 

Supply 

Conductors 

and Supply 

Cables, 

750-22,500 

Volts 

F 

Supply 

Conductors 

And 

Supply 

Cables, 

22.5-300 kV

G 

Supply 

Conductors 

and Supply 

Cables, 

300-550 

kV(mm) 

14 

Radial 

clearance of 

bare line 

conductors 

from 

vegetation in 

Extreme and 

Very High 

Fire Threat 

Zones in 

Southern 

California 

(aaa) (ddd) 

(hhh)(jjj)

 

18 

inches 

(bbb) 

48 inches 

(bbb) (iii)

48 inches 

(fff)

120 inches 

(ggg) 

(fff) Clearances in this case shall be increased for conductors operating above 88 72 kV, to the following: 

1. Conductors operating between 88 72 kV and a 110 kV shall maintain a 60 72 inch clearance. 

2. Conductors operating above 110 kV shall maintain a 120 inch clearance. 

(ggg) Shall be increased by 0.40 inch per kV in excess of 500 kV. 

(hhh) Extreme and Very High Fire Threat Zones are defined by California Department of Forestry and Fire Protection’s 

Fire and Resource Assessment Program (FRAP) Fire Threat Map. The FRAP Fire Threat Map is to be used to 

establish approximate boundaries for purposes of this rule. The boundaries of the map are to be broadly 

construed, and utilities should use their own expertise and judgment to determine if local conditions require them 

to adjust the boundaries of the map. Southern California shall be defined as the following: Santa Barbara, 

Ventura, San Bernardino, Riverside, Los Angeles, Orange, and San Diego Counties. 

(iii) May be reduced to 18 inches for conductors operating less than 2.4 kV. 

(jjj) Clearances in this case shall not apply to orchards of fruit, nut or citrus trees that are plowed or cultivated. In those 

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areas Case 13 clearances shall apply. 

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Consensus Proposal 5 re: GO 95, Rules 23, 44.1, 44.2, and 44.3

Proposed Revisions to Current Rules Shown with Strikeout and Underline 

Rule 23.0 

Reconstruction means that work which in any way changes the identity of the 

pole, tower or structure on which it is performed. A change in grade of 

construction or class of circuit is considered reconstruction. For exceptions see 

Rule 12.1. 

44.1 Installation and Reconstruction 

Lines and elements of lines upon installation or reconstruction, shall provide as a 

minimum the safety factors specified in Table 4 for vertical loads and loads 

transverse to lines and for loads longitudinal to lines except where longitudinal 

loads are balanced or where there are changes in grade of construction (see 

Rules 47.3, 47.4 and 47.5). The design shall consider the structural loading and 

mechanical strength requirements of all supply and communication facilities 

planned to occupy the structure. For purposes of this rule, the term “planned” 

applies to the facilities intended to occupy the structure that are actually known 

to the constructing utility company at the time of design. 

44.2 Additional Construction 

Any utility supply or communication company planning the addition of facilities 

that materially increase the vertical, transverse or longitudinal loading on a 

structure shall perform a loading calculation to ensure that the addition of the 

facilities will not reduce the safety factors below the values specified by Rule 44.3

Section IV. Such utility company shall maintain these pole loading calculations 

for five years and shall provide such information to authorized joint use pole 

occupants and the Commission upon request. 

All other utilities or companies on the subject pole shall cooperate with the utility

company performing the load calculations described above including, but not 

limited to, providing intrusive pole loading test data results and other data 

necessary to perform those such calculations. 

Note: Nothing contained in this rule shall be construed as allowing the safety 

factor of a facility

to be reduced below the required values specified in Rules 44.1 and 44.3.

44.3 - Replacement 

Lines or parts thereof shall be replaced or reinforced before safety factors have 

been reduced (due to deterioration and/or installation of additional facilities) in 

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Grades “A” and “B” construction to less than two-thirds of the construction 

safety factors specified in Rule 44.1 and in Grades “C” and “F” construction to 

less than one-half of the construction safety factors specified in Rule 44.1. Poles 

in Grade “F” construction shall also conform to the requirements of Rule 81.3-A. 

In no case shall the application of this be held to permit the use of structures or 

any member of any structure with a safety factor less than one. 

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Consensus Proposal 6 re: GO 165, Sections I – IV

Proposed Revisions to GO 165 Shown with Strikeout and Underline 

Appendix A 

Public Utilities Commission of the State of California 

Inspection Cycles Requirements for Electric Distribution and Transmission

Facilities

___________________________________________________________________________ 

Adopted March 31, 1997 Effective March 1, 1997 

(D.97-03-070 in I.95-02-015 and R.96-11-004) 

Amended August 20, 2009 

(D.09-08-029 in R.08-11-005) 

___________________________________________________________________________________________________________________ 

I. Purpose 

The purpose of this General Order is to establish minimum requirements for electric 

distribution and transmission facilities (excluding those facilities contained in a substation)

regarding inspections (including maximum allowable inspection cycle lengths), condition 

rating, scheduling and performance of corrective action, record-keeping, and reporting, in 

order to ensure safe and high-quality electrical service, and to implement the provisions 

of Section 364 of Assembly Bill 1890, Chapter 854, Statutes of 1996. 

II. Applicability

As of March 31, 1997, tThis General Order applies to Pacific Gas and Electric Company, 

Pacificorp, San Diego Gas and Electric Company, Sierra Pacific Power Company, and 

Southern California Edison Company all electric distribution and transmission facilities 

(excluding those facilities contained in a substation) that come within the jurisdiction of this 

Commission, located outside of buildings, including electric distribution and transmission 

facilities that belong to non-electric utilities. 

The requirements of this order are in addition to the requirements imposed upon utilities 

under General Orders 95 and 128 to maintain a safe and reliable electric system. Nothing in 

this General Order relieves any utility from any requirements or obligations that it has under 

General Orders 95 and 128. 

This General Order does not apply to facilities of communication infrastructure 

providers.

III. Definitions Distribution Facilities 

A Definitions 

For the purpose of this General Order, 

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A1 "Urban" shall be defined as those areas with a population of more than 1,000 

persons per square mile as determined by the United States Bureau of the 

Census. 

B2 "Rural" shall be defined as those areas with a population of less than 1,000 

persons per square mile as determined by the United States Bureau of the 

Census. 

C3 "Patrol" shall be defined as a simple visual inspection, of applicable utility 

equipment and structures, that is designed to identify obvious structural 

problems and hazards. Patrols may be carried out in the course of other 

company business. 

D4 "Detailed" inspection shall be defined as one where individual pieces of 

equipment and structures are carefully examined, visually and through use of 

routine diagnostic test, as appropriate, and (if practical and if useful information 

can be so gathered) opened, and the condition of each rated and recorded. 

E5 "Intrusive" inspection is defined as one involving movement of soil, taking 

samples for analysis, and/or using more sophisticated diagnostic tools beyond 

visual inspections or instrument reading. 

F6 "Corrective Action" shall be defined as maintenance, repair, or replacement 

of utility equipment and structures so that they function properly and safely. 

IV. B Standards for Inspection, Record-keeping, and Reporting 

Each utility subject to this General Order shall conduct inspections of its 

distribution facilities, as necessary, to assure reliable, high-quality, and safe 

operation, but in no case may the period between inspections (measured in years) 

exceed the time specified in the attached tTable 1. 

Each utility subject to this General Order shall submit to the Commission by no 

later than July 1, 1997, compliance plans for the inspections and record-keeping 

required by this order. These compliance plans will include the proposed forms 

and formats for annual reports and source records, as well as the utility's plans for 

the types of inspections and equipment to be inspected during the coming year. 

For detailed and intrusive inspections, schedules should be detailed enough (in 

terms of the months of inspection and the circuit, area, or equipment to be 

inspected) to allow staff to confirm that schedule inspections are proceeding as 

planned. For patrol inspections, companies should explain how all required 

facilities will be covered during the year. Energy Division or any successor staff 

divisions may prescribe changes relating to data, definitions, reporting and 

record-keeping formats and forms when and as necessary. 

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Each utility subject to this General Order shall submit an annual report detailing 

its compliance with this General Order under penalty of perjury. The first report 

required under this section shall be filed with the Commission by no later than 

July 1, 1998. Each utility shall file subsequent annual reports for every following 

year by no later than July 1. The report shall identify the number of facilities, by 

type which have been inspected during the previous period. It shall identify 

those facilities which were scheduled for inspection but which were not 

inspected according to schedule and shall explain why the inspections were not 

conducted, and a date certain by which the required inspection will occur. The 

report shall also present the total and percentage breakdown of equipment rated 

at each condition rating level, including that equipment determined to be in 

need of corrective action. Where corrective action was scheduled during the 

reporting period, the report will present the total and percentage of equipment 

which was and was not corrected during the reporting period. For the latter, an 

explanation will be provided, including a date certain by which required 

corrective action will occur. The report will also present totals and the 

percentage of equipment in need of corrective action, but with a scheduled date 

beyond the reporting period, classified by the amount of time remaining before 

the scheduled action. All of the above information shall be presented for each 

type of facility identified in the attached table and shall be aggregated by 

district. 

C Record Keeping 

The companyutility shall maintain records of inspection activities which shall be 

made available to parties or pursuant to Commission rules upon 30 days notice. 

Commission staff shall be permitted to inspect such records consistent with Public 

Utilities Code Section 314 (a). 

For all inspections, within a reasonable period, company records shall specify the 

circuit, area, facility or equipment inspected, the name of the inspector, the date of 

the inspection, and any problems (or items requiring corrective action) identified 

during each inspection, as well as the scheduled date of corrective action. For 

detailed and intrusive inspections, companies shall also rate the condition of 

inspected equipment. Upon completion of corrective action, company records will 

show the nature of the work, the date, and the identity of persons performing the 

work. 

 D Reporting 

By July 1st each utility subject to this General Order shall submit an annual report 

for the previous year under penalty of perjury.

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The report shall list four categorical types of inspections: Patrols, Overhead 

Detailed, Underground Detailed and Wood Pole Intrusive. The report shall 

denote the total units of work by inspection type for the reporting period and the 

number of outstanding (not completed) inspections within the same reporting 

period for each of the four categories. 

Sample Report Template:

Type of Inspections

(1) Due (2) Outstanding (3)

Patrols xxx xxx

OH Detailed xxx xxx

UG Detailed xxx xxx

Wood Pole Intrusive xxx xxx

Notes:

1) Each utility will define their reporting unit basis (e.g., circuit, grid, facility / 

equipment). 

2) Total inspections due in the reporting period. (Does not include outstanding inspections 

from prior years.)

3) Total inspections required that were not completed in the reporting period. (Does not 

include outstanding inspections from prior years.)

 E Changes to Requirements Herein

If, in a particular case, exemption from or modification of any of the requirements herein 

is desired, the Commission will consider a request for such exemption or 

modification when accompanied by a full statement of conditions existing and the 

reasons why such exemption or modification is asked and is believed to be 

justifiable. It is to be understood that, unless otherwise ordered, any exemption or 

modification so granted shall be limited to the particular case covered by the 

request.

IV. Transmission Facilities

Each utility shall prepare and follow procedures for conducting inspections and 

maintenance activities for transmission lines. 

Each utility shall maintain records of inspection and maintenance activities. 

Commission staff shall be permitted to inspect records and procedures consistent with 

Public Utilities Code Section 314 (a). 

/s/ Wesley M. Franklin

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Paul Clanon

Wesley M. Franklin

Paul Clanon

Executive Director

Appendix A 

Table 1

Electric Company System Distribution Inspection Cycles (Maximum Intervals in 

Years)

 

Patrol Detailed Intrusive

 

Urban Rural Urban Rural Urban Rural

Transformers

Overhead 1 21 5 5 --- --- 

Underground 1 2 3 3 --- --- 

Padmounted 1 2 5 5 --- --- 

Switching/Protective Devices

Overhead 1 21 5 5 --- --- 

Underground 1 2 3 3 --- --- 

Padmounted 1 2 5 5 --- --- 

Regulators/Capacitors 

Overhead 1 21 5 5 --- --- 

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Underground 1 2 3 3 --- --- 

Padmounted 1 2 5 5 --- --- 

 

Overhead Conductor and Cables 1 21 5 5 --- --- 

Streetlighting 1 2 x x --- --- 

Wood Poles under 15 years 1 2 x x --- --- 

Wood Poles over 15 years which have not 

been subject to intrusive inspection 1 2 x x 10 10 

Wood poles which passed intrusive 

inspection --- --- --- --- 20 20 

 

(1) Patrol inspections in rural areas shall be increased to once per year in Extreme and 

Very High Fire Threat Zones in the following counties: Santa Barbara, Ventura, Los 

Angeles, San Bernardino, Orange, Riverside, and San Diego. Extreme and Very High 

Fire Threat Zones are defined by California Department of Forestry and Fire 

Protection’s Fire and Resource Assessment Program (FRAP) Fire Threat Map. The 

FRAP Fire Threat Map is to be used to establish approximate boundaries and Utilities 

should use their own expertise and judgment to determine if local conditions require 

them to adjust the boundaries of the map. 

Note: This General Order does not apply to cathodic protection systems associated 

with natural gas facilities. 

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Contested Proposal 1A re: GO 95, Rule 11 (CPSD) 

CPSD’s Proposed Revisions to Rule 11 Shown with Strikeout and Underline 

11 Purpose of Rules

The purpose of these rules is to formulate, for the State of California, uniform

requirements for overhead electrical line design, construction, and maintenance,

the application of which will einsure adequate service and secure safety to 

persons engaged in the construction, maintenance, operation or use of overhead 

electrical lines and to the public in general. 

Contested Proposal 1B re: GO 95, Rule 11 (CIP Coalition) 

CIP Coalitions’ Proposed Revisions to Rule 11 Shown 

with Strikeout and Underline 

11 Purpose of Rules

The purpose of these rules is to formulate, for the State of California, uniform

requirements for overhead electrical line design, construction, and maintenance,

the application of which will einsure adequate service and secure safety to 

persons engaged in the construction, maintenance, operation or use of overhead 

electrical lines and to the public in general. 

Contested Proposal 2 re: GO 95, Rule 12 (CPSD) 

CPSD’s Proposed Revisions to Rule 12 Shown with Strikeout and Underline 

12 Applicability of Rules

These rules apply to all overhead electrical supply and communication facilities 

that come within the jurisdiction of this Commission, located outside of 

buildings, including facilities that belong to non-electric utilities and publiclyowned utility electric supply facilities, as follows: 

12.1 Construction and Reconstruction of Lines 

12.2 Maintenance of Lines 

12.3 Lines Constructed Prior to This Order 

12.4 Reconstruction or Alteration 

12.5 Emergency Installation 

12.6 Third Party Nonconformance 

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Contested Proposal 3A re: GO 95, Rule 18 (CIP Coalition)

CIP Coalition’s Proposed Revisions to Rule 18 Shown 

with Strikeout and Underline 

The CIP Coalition’s proposed revisions to Rule 18 incorporate the 

consensus revisions to Rule 18 that replace the term “violation” with the term 

“nonconformance.” 

18 Reporting and Resolution of Safety Hazards Discovered by Utilities 

For purposes of this rule, “Safety Hazard” means a condition that poses a 

significant threat to human life or property.

“Extreme and Very High Fire Threat Zones” are defined in the Commission 

Decision 09-08-029. “Southern California” is defined as the following: Santa 

Barbara, Ventura, San Bernardino, Riverside, Los Angeles, Orange, and 

San Diego.

Part A: Resolution of Safety Hazards And General Order 95 

Violations/Nonconformances

(1)(a) Each company (including utilities and CIPs) is responsible for taking 

appropriate corrective action to remedy Safety Hazards and GO 95 

violations/nonconformances posed by their its facilityies. 

(b) Upon completion of the corrective action, the company’s records shall 

show, with sufficient detail, the nature of the work, the date, and the 

identity of persons performing the work. Prior to the work being 

completed, the company shall document the current status of the safety 

hazard, including whether the safety hazard is located in an Extreme and 

Very High Fire Threat Zone in Southern California, and shall include a 

scheduled date of corrective action. These records shall be preserved by 

the company for at least five years and shall be of sufficient detail to allow 

Commission staff during an audit, if any, to determine that the safety 

hazard has been remedied. The records made available to Commission 

staff upon 30 days noticeimmediately upon request. Additionally, for any 

work completed after the initial scheduled date of corrective action, the 

company shall document the reason or reasons that the work was not 

completed by the original scheduled date of corrective action.

For purposes of this rule, “safety hazard” means a condition that poses a 

significant threat to life or property, including, but not limited to, the 

ignition of a wildland or structure fire. “Extreme and Very High Fire 

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Threat Zones” are defined in the Commission decision issued in Phase I of 

R.08- 11-005. “Southern California” is defined as the following: Santa 

Barbara, Ventura, San Bernardino, Riverside, Los Angeles, Orange, and 

San Diego Counties.

Companies that have existing General Order 165 auditable inspection and 

maintenance programs that are consistent with the purpose of Rule 18 

shall continue to follow their General Order 165 programs. All companies 

shall establish an auditable maintenance program for their facilities and 

lines. Further, all companies must include a timeline for corrective actions 

to be taken following the identification of a safety hazard or violation of 

General Orders 95 or 128 on the companies’ facilities. 

The auditable maintenance program should be developed and 

implemented based on the following principles.

(2)(a) All companies shall establish an auditable maintenance program for their 

facilities and lines. All companies must include a timeline for corrective 

actions to be taken following the identification of a Safety Hazard or 

violations/nonconformances with General Order 95 on the company’s 

facilities. The auditable maintenance program shall prioritize corrective 

actions consistent with the priority levels set forth below and based on (1) 

Priorities shall be assigned based on the specifics of the safety hazard or 

violation as related to direct impact and the probability for impact on 

safety or reliability using the following factors:, as appropriate: 

• Safety and reliability as specified in the priority levels below;

• Type of facility or equipment; 

• Location;, including whether the Safety Hazard or 

violation/nonconformance is located in an Extreme or Very High Fire 

Threat zone in Southern California; 

• Accessibility; 

• Climate; 

• Direct or potential impact on operations, customers, electrical company 

workers, communications workers, and the general public; 

o Whether the safety hazard or violation is located in an Extreme or Very 

High Fire Threat Zone

(2) There willshall be three 3 priority levels, as follows. 

(a) (i) Level 1: 

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• Immediate safety and/or reliability risk with high probability for 

significant impact. 

• Take action immediately, either by fully repairing the condition, or by 

temporarily repairing and reclassifying the condition to a lower 

priority. 

(b) (ii) Level 2: 

• Variable (non-immediate high to low) safety and/or reliability risk. 

• Take action to correct within specified time period (fully repair, or by 

temporarily repairing and reclassifying the condition to a lower 

priority). 

• Time period for correction to be determined at the pointtime of 

identification by a qualified company representative, but not to exceed 

59 months:.

• Overhead: 0-59 months

o Where communications company actions result in electric utility GO 

violations, the electric utility’s remedial action will be to transmit a 

single documented notice of identified violations to the 

communications company for compliance.

(c) (iii) Level 3: 

• Acceptable safety and/or reliability risk. 

• Take action (re-inspect, re-evaluate, or repair) at or before the next 

detailed inspection as appropriate. 

(b) (d) Exceptions (Levels 2 and 3 only) –Correction times may be extended 

under reasonable circumstances, such as: 

• Third party refusal 

• Customer issue 

• No access 

• Permits required 

• System emergencies (e.g. fires, severe weather conditions) 

(3) Companies that have existing General Order 165 auditable inspection and 

maintenance programs that are consistent with the purpose of Rule 18A 

shall continue to follow their General Order 165 programs.

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(3) Upon completion of the corrective action, the company’s records shall 

show the nature of the work, the date, and the identity of persons 

performing the work. These records should be preserved by the company 

for at least five years.

(4) The company shall prioritize implementing this maintenance plan within 

the Extreme and Very High Fire Threat Zones of Southern California. 

With the exception of a safety hazard or violation requiring immediate 

correction, a company must correct a violation or safety hazard within 30 

days of discovering or being notified of a violation or safety hazard, if the 

violation or safety hazard violates a clearance requirement listed in 

columns E, F, or G of Table 1 in this General Order, or violates a pole 

overloading requirement in Rule 44.3 of this General Order, and is located 

in an Extreme and Very High Fire Threat Zone in Southern California. The 

company must correct a violation or safety hazard within 30 days if the 

utility is notified that the violation must be corrected to alleviate a 

significant safety risk to any utility’s employees. 

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Contested Proposal 3B re: GO 95, Rule 18 (SDG&E)

SDG&E’s Proposed Revisions to Rule 18A Shown with 

Strikeout and Underline 

SDG&E’s proposed revisions to Rule 18 incorporate the consensus 

revisions to Rule 18 that replace the term “violation” with the term 

“nonconformance.” 

18 Reporting and Resolution of Safety Hazards Discovered by Utilities 

For purposes of this rule, “Safety Hazard” means a condition that poses a 

significant threat to human life or property.

“Extreme and Very High Fire Threat Zones” are defined in the Commission 

Decision 09-08-029. “Southern California” is defined as the following: Santa 

Barbara, Ventura, San Bernardino, Riverside, Los Angeles, Orange, and San 

Diego Counties.

Part A: Resolution of Safety Hazards And General Order 95 Violations/

Nonconformances

(1)(a) Each company (including utilities and CIPs) is responsible for taking 

appropriate corrective action to remedy Safety Hazards and GO 95 

violations/nonconformances posed by their its facilityies. 

(b) Upon completion of the corrective action, the company’s records shall 

show the date and with sufficient detail, the nature of the work, the date,

and the identity of persons performing the work. Prior to the work being 

completed, the company shall document the current status of the safety 

hazard, including whether the safety hazard is located in an Extreme and 

Very High Fire Threat Zone in Southern California, and shall include a 

scheduled date of corrective action. These records shall be preserved by 

the company for at least five years, and shall be of sufficient detail to allow 

Commission staff during an audit, in any, to determine that the safety 

hazard has been remedied made available to Commission staff upon 30 

days notice. The records shall be made available to Commission staff 

immediately upon request. Additinally, for any work completed after 

initial scheduled date of corrective action, the company shall document the 

reason or reasons that the work was not completed by the original 

scheduled date of correction action.

For purposes of this rule, “safety hazard” means a condition that poses a 

significant threat to life or property, including, but not limited to, the 

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ignition of a wildland or structure fire. “Extreme and Very High Fire 

Threat Zones” are defined in the Commission decision issued in Phase I of 

R.08-11-005. “Southern California” is defined as the following: Santa 

Barbara, Ventura, San Bernardino, Riverside, Los Angeles, Orange, and 

San Diego Counties.

Companies that have existing General Order 165 auditable inspection and 

maintenance programs that are consistent with the purpose of Rule 18

shall continue to follow their General Order 165 programs. 

(2)(a) All companies shall establish an auditable maintenance program for their 

facilities and lines. Further, All companies must include a timeline for 

corrective actions to be taken following the identification of a Safety 

Hazard or violations/nonconformances of with General Orders 95 or 128 

on the companies’company’s facilities. The auditable maintenance 

program should be developed and implementedshall prioritize corrective 

actions consistent with the priority levels set forth below and based on the

following principles.factors, as appropriate: 

(1) Priorities shall be assigned based on the specifics of the safety 

hazard or violation as related to direct impact and the probability for 

impact on safety or reliability using the following factors:

• Safety and reliability as specified in the priority levels below;

• Type of facility or equipment; 

• Location;, including whether the Safety Hazard or nonconformance is 

located in an Extreme or Very High Fire Threat Zone in Southern 

California;

• Accessibility; 

• Climate; 

• Direct or potential impact on operations, customers, electrical company 

workers, communications workers, and the general public;

• Whether the safety hazard or violation is located in an Extreme or Very 

High Fire Threat zone.

(2) There willshall be three3 priority levels, as follows:. 

(ai) Level 1: 

• Immediate safety and/or reliability risk with high probability for 

significant impact. 

• Take action immediately, either by fully repairing the condition, or by 

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temporarily repairing and reclassifying the condition to a lower 

priority. 

(bii) Level 2: 

• Variable (non-immediate high to low) safety and/or reliability risk. 

• Take action to correct within specified time period (fully repair, or by 

temporarily repairing and reclassifying the condition to a lower 

priority). 

• Time period for correction to be determined at the pointtime of 

identification by a qualified company representative:, but not to exceed; 

(1) 12 months for violations/nonconformances that compromise worker safety, 

(2) 12 months for violations/nonconformances that create a fire risk and are 

located in an Extreme or Very High Fire Threat Zone in Southern California, and 

(3) 59 months for all other Level 2 violations/nonconformances.

o Overhead: 0-59 months

• Where communications company actions result in electric utility GO 

violations, the electric utility’s remedial action will be to transmit a 

single documented notice of identified violations to the 

communications company for compliance.:

(ciii) Level 3: 

• Acceptable safety and/or reliability risk. 

• Take action (re-inspect, re-evaluate, or repair) at or before the next 

detailed inspection.as appropriate. 

(d) Exceptions (Levels 2 and 3 only) –b) Correction times may be extended 

under reasonable circumstances, such as: 

• Third party refusal 

• Customer issue 

• No access 

• Permits required 

• System emergencies (e.g. fires, severe weather conditions) 

(3) Upon completion of the corrective action, the company’s records shall 

show the nature of the work, the date, and the identity of persons 

performing the work. These records should be preserved by the 

company for at least five years.

(3) Companies that have existing General Order 165 auditable inspection and 

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maintenance programs that are consistent with the purpose of Rule 18A shall 

continue to follow their General Order 165 programs.

(4) The company shall prioritize implementing this maintenance plan within 

the Extreme and Very High Fire Threat Zones of Southern California. With the 

exception of a safety hazard or violation requiring immediate correction, a 

company must correct a violation or safety hazard within 30 days of discovering 

or being notified of a violation or safety hazard, if the violation or safety hazard 

violates a clearance requirement listed in columns E, F, or G of Table 1 in this 

General Order, or violates a pole overloading requirement in Rule 44.3 of this 

General Order, and is located in an Extreme and Very High Fire Threat Zone in 

Southern California. The company must correct a violation or safety hazard 

within 30 days if the utility is notified that the violation must be corrected to 

alleviate a significant safety risk to any utility’s employees. 

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Contested Proposal 4 re: GO 95, Rule 18C (MGRA) 

MGRA’s Proposed New Rule 18C Shown with Underline 

18C – Contingency Planning

Electric utilities shall have in place contingency plans for predicting and 

identifying hazard conditions that exceed wind loadings of Rule 43 in areas 

designated as having high fire risk during periods of high fire danger. These 

plans shall include measures to prevent ignitions of wildland fires by equipment 

that meets GO 95 wind loading and vegetation management requirements. 

Contested Proposal 5 re: GO 95, Rule 31.1 (Joint Utilities) 

Joint Utilities’ Proposed Revisions to Rule 31.1 Shown with Underline 

31.1 Design, Construction and Maintenance 

Electrical supply and communication systems shall be designed, constructed, and 

maintained for their intended use, regard being given to the conditions under which 

they are to be operated, to enable the furnishing of safe, proper, and adequate service. 

For all particulars not specified in these rules, design, construction, and maintenance 

should be done in accordance with accepted good practice for the given local conditions 

known at the time by those responsible for the design, construction, or maintenance of 

[the] communication or supply lines and equipment. 

For all particulars specified in this Order, a supply or communications company 

is in compliance with this rule if it designs, constructs and maintains a facility in 

accordance with such particulars. For all particulars not specified in this Order, 

a supply or communications company is in compliance with this rule if it 

designs, constructs and maintains a facility in accordance with accepted good 

practice. 

All work performed on public streets and highways shall be done in such a manner that 

the operations of other utilities and the convenience of the public will be interfered with 

as little as possible and no conditions unusually dangerous to workmen, pedestrians or 

others shall be established at any time. 

Note: The standard of accepted good practice should be applied on a case by case basis. For 

example, the application of “accepted good practice” may be aided by reference to any of the 

practices, methods, and acts engaged in or approved by a significant portion of the relevant 

industry, or which may be expected to accomplish the desired result with regard to safety and 

reliability at a reasonable cost. 

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Contested Proposal 6A re: GO 95, Rule 31.2 (CIP-1) 

Proposed Revisions to Rule 31.2 Shown with Underline 

31.2 Inspection of Lines

Lines shall be inspected frequently and thoroughly for the purpose of insuring that 

they are in good condition so as to conform with these rules. Lines temporarily out 

of service shall be inspected and maintained in such condition as not to create a 

hazard. 

A. Communications Lines In Specified Fire Areas: 

Communication lines shall be inspected in Specified Fire Areas, as follows:

(1) Patrols shall be performed not less often than once every three (3) years on 

overhead communications lines installed on joint use poles with electric 

distribution or transmission facilities, as well as on communication lines one 

span away.

Patrol means a simple visual inspection of communications equipment and 

structures that is designed to identify obvious structural problems and 

hazards. Patrols may be carried out in the course of other company 

business.

(2) Detail Inspections shall be performed not less often than once every nine 

(9) years on overhead communications lines installed on joint use poles with 

electric distribution or transmission facilities, as well as on communication 

lines one span away. 

Detail Inspection means a careful visual inspection of communications 

equipment and structures using inspection tools such as binoculars and 

measuring devices, as appropriate. Detail Inspections may be carried out in 

the course of other company business.

For all patrols and details, records shall specify the facility or equipment 

inspected; the name of the inspector; the date of the inspection; and any 

problems (or items requiring corrective action) identified during each inspection, 

as well as the scheduled date of corrective action. Records of Patrols and Details 

shall be made available to Commission staff upon 30 days notice. 

Note: Specified Fire Areas shall be defined as [in Southern California – FRAP 

Maps; in Central and Northern California - to be worked out in workshops].

Electric Lines: shall be inspected in compliance with the minimum intervals set 

forth in General Order 165. 

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Contested Proposal 6B re: GO 95, Rule 31.2 (CIP-2) 

Proposed Revisions to Rule 31.2 Shown with Strikeout and Underline 

31.2 Inspection of Lines

A. Lines shall be inspected frequently and thoroughly for the purpose of 

einsuring that they are in good condition so as to conform with these rules. 

Lines temporarily out of service shall be inspected and maintained in such 

condition as not to create a hazard. 

For the purpose of the remaining subsections of this Rule:

“Patrol” means a simple visual inspection designed to identify obvious 

structural problems and hazards. Patrols may be carried out in the course of 

other company business.

 “Specified Fire Areas” shall be defined as: for Southern California, the 

Extreme and Very High Threat Zones on the California Department of 

Forestry and Fire Protection’s Fire and Resource Assessment Program’s map 

in Santa Barbara, Ventura, Los Angeles, Orange, San Diego, Riverside, and 

San Bernardino; for Central and Northern California, [to be determined in the 

workshops.]

B. Patrols shall encompass overhead communication lines installed on joint use 

poles with electric distribution facilities, as well as those facilities that are one 

span away in the Specified Fire Areas. Each Specified Fire Area shall be 

inspected not less than once every five (5) years.

C. Records demonstrating compliance with subsection (B) of this Rule shall be 

maintained. Company records shall specify the plant, area or equipment 

inspected, the name of the inspector and the date of the inspection. Such 

documentation shall be retained for five (5) years.

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A-30

Contested Proposal 6C re: GO 95, Rule 31.2 and Rule 80.1 (CPSD) 

Proposed Revisions to Rule 31.2 Shown with Strikeout and Underline 

31.2 Inspection of Lines

Lines shall be inspected frequently and thoroughly for the purpose of einsuring that 

they are in good condition so as to conform with these rules. Lines temporarily out of 

service shall be inspected and maintained in such condition as not to create a hazard. 

A. Communication Lines (See Rule 80.1)

B. Supply Lines shall be inspected in compliance with the requirements of 

General Order 165.

80.1 Inspection Requirements for Communication Lines:

A. Each company shall prepare, follow and modify as necessary procedures 

for conducting inspections for all Communication Lines. The procedures 

at a minimum shall contain the following:

• Maximum allowable intervals between inspections. The intervals 

between inspections shall be based upon the following factors:

• Proximity to electric facilities

• Terrain 

• Accessibility

• Location

In no case may the period between inspections (measured in calendar 

years) for Communication Lines located on Joint Use Poles (See Rule 21.8) 

that support Supply Lines, as well as those Communication Lines attached 

to a pole that are one span away from Joint Use Poles that support Supply 

Lines, exceed the time specified in the below Table. 

Patrol

Urban Rural Detailed

1 21 10

(1) Patrol inspections in rural areas shall be increased to once per year in 

Extreme and Very High Fire Threat Zones in the following counties: 

Santa Barbara, Ventura, Los Angeles, San Bernardino, Orange, 

Riverside, and San Diego. Extreme and Very High Fire Threat Zones 

are defined by California Department of Forestry and Fire Protection’s 

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A-31

Fire and Resource Assessment Program (FRAP) Fire Threat Map. The 

FRAP Fire Threat Map is to be used to establish approximate 

boundaries and Utilities should use their own expertise and judgment 

to determine if local conditions require them to adjust the boundaries of 

the map.

• Methodology to ensure that all lines are subjected to:

• Detailed Inspections

Note: For the purpose of this rule Detailed Inspection shall be 

defined as a careful visual inspection of Communication 

facilities and structures using inspection tools such as 

binoculars and measuring devices, as appropriate.

• Patrol Inspections

Note: For the purpose of this rule Patrol Inspection shall be defined 

as a simple visual inspection, of applicable communications 

facilities equipment and structures that is designed to identify 

obvious structural problems and hazards. Patrol inspections 

may be carried out in the course of other company business.

• Procedures specifying what problems shall be identified.

Each company shall maintain records of inspections. Commission staff shall be 

permitted to inspect records and procedures consistent with Public Utilities Code 

Section 314 (a). 

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Contested Proposal 6D re: GO 95, Rule 31.2 and Rule 80.1 (SDG&E) 

Proposed Revisions Shown in with Strikeout and Underline 

31.2 Inspection of Lines

Lines shall be inspected frequently and thoroughly for the purpose of einsuring that 

they are in good condition so as to conform with these rules. Lines temporarily out of 

service shall be inspected and maintained in such condition as not to create a hazard. 

A. Communication Lines (See Rule 80.1)

B. Supply Lines shall be inspected in compliance with the requirements of 

General Order 165.

80.1 Inspection Requirements for Communication Lines:

Each company shall prepare, follow and modify as necessary procedures 

for conducting inspections for all Communication Lines. The procedures 

at a minimum shall contain the following:

• Maximum allowable intervals between inspections. The intervals 

between inspections shall be based upon the following factors:

• Proximity to electric facilities

• Terrain 

• Accessibility

• Location

In no case may the period between inspections (measured in years) for

Communication Lines located on Joint Use Poles (See Rule 21.8) that 

contain Supply Circuits (See Rule 20.6-D), as well as those 

Communication Lines attached to a pole that are within three spans of 

Joint Use Poles that contain Supply Circuits, exceed the time specified 

in the below Table. 

Patrol

Urban Rural Detailed

1 21 101

(1) Patrol inspections in rural areas shall be increased to once per year, 

and detailed inspections shall be increased to once every five years, 

in Extreme and Very High Fire Threat Zones in the following 

counties: Santa Barbara, Ventura, Los Angeles, San Bernardino, 

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Orange, Riverside, and San Diego. Extreme and Very High Fire 

Threat Zones are defined by California Department of Forestry and 

Fire Protection’s Fire and Resource Assessment Program (FRAP) 

Fire Threat Map. The FRAP Fire Threat Map is to be used to 

establish approximate boundaries and Utilities should use their own 

expertise and judgment to determine if local conditions require them 

to adjust the boundaries of the map.

• Methodology to ensure that all lines are subjected to:

• Detailed Inspections

Note: For the purpose of this rule Detailed Inspection shall be 

defined as a careful visual inspection of Communication 

facilities and structures using inspection tools such as 

binoculars and measuring devices, as appropriate.

• Patrol Inspections

Note: For the purpose of this rule Patrol Inspection shall be defined 

as a simple visual inspection, of applicable communications 

facilities equipment and structures that is designed to identify 

obvious structural problems and hazards. Patrol inspections 

may be carried out in the course of other company business.

• Procedures specifying what problems shall be identified.

Each company shall maintain records of inspections. Commission staff 

shall be permitted to inspect records and procedures consistent with 

Public Utilities Code Section 314 (a). 

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A-34

Contested Proposal 6E re: GO 95, Rule 31.2 and Rule 80.1B (CPSD) 

Proposed New Rule 80.1B Shown with Underline 

80.1 Inspection Requirements for Communication Lines:

B. Intrusive Inspections

Wood poles supporting only Communication Lines or equipment, that are:

Located in Extreme or Very High Fire Threat Zones in Southern California 

and inter-set between joint use poles supporting Supply Lines, 

Or, 

Located in Extreme or Very High Fire Threat Zones in Southern California 

and extend up to three spans from a joint use pole supporting Supply 

Lines, 

Or,

Located in areas outside Extreme or Very High Fire Threat Zones in 

Southern California and extend one span from a joint use pole supporting 

Supply Lines, shall be intrusively inspected accordance with the schedule 

established in General Order 165 for wood poles that support Supply 

Lines.

Note: For the purpose of this rule Intrusive Inspections shall be defined as 

an inspection involving movement of soil, and/or using more 

sophisticated diagnostic tools beyond visual inspections or instrument 

reading. 

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A-35

Contested Proposal 7A re: GO 95, Rule 35, Paragraph 4 (Joint Utilities) 

Proposed New Paragraph Shown with Underline 

35 Vegetation Management 

Insert new fourth Paragraph as follows: 

Whenever a property owner obstructs access to, or fails to make accessible, 

overhead facilities for vegetation management activities, such that the 

supply company cannot inspect its facilities or there is an imminent threat of 

violation of required regulatory or statutory clearances, the supply 

company, at its discretion and with proper notice, may discontinue electric 

service the property owner is receiving at any location where the owner 

may receive the supply company’s electric service. “Proper notice” shall, at 

a minimum, consist of five days written notice, unless the condition poses 

an imminent safety hazard to the public. 

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A-36

Contested Proposal 7B re: GO 95, Rule 35, Exception 3 (Joint Utilities)

Proposed New Exception Shown with Strikeout and Underline 

35 Vegetation Management

Where overhead conductors traverse trees and vegetation, safety and reliability 

of service demand that certain vegetation management activities be performed in 

order to establish necessary and reasonable clearances. The minimum clearances 

established in Table 1, Cases 13 and 14, measured between line conductors and 

vegetation under normal conditions, shall be maintained. (Also see Appendix E 

for tree trimming guidelines). 

When a utility has actual knowledge, obtained either through normal operating 

practices or notification to the utility, dead, rotten and diseased trees or portions 

thereof, that overhang or lean toward and may fall into a span, should be 

removed. 

Communication and electric supply circuits, energized at 750 volts or less, 

including their service drops, should be kept clear of vegetation in new 

construction and when circuits are reconstructed or repaired, whenever 

practicable. When a utility has actual knowledge, obtained either through 

normal operating practices or notification to the utility, that any circuit energized 

at 750 volts or less shows strain or evidences abrasion from vegetation contact, 

the condition shall be corrected by reducing conductor tension rearranging or 

replacing the conductor, pruning the vegetation or placing mechanical protection 

on the conductor(s). For the purpose of this rule, abrasion is defined as damage 

to the insulation resulting from the friction between the tree and conductor. 

Scuffing or polishing of the insulating covering is not considered abrasion. 

Strain on a conductor is present when there is additional tension causing a 

deflection of the conductor beyond the slack of the span. Contact between 

vegetation and conductors, in and of itself, does not constitute a violation of the 

rule. 

EXCEPTIONS: 

1. Rule 35 requirements do not apply to conductors, or aerial cable that complies 

with Rule 57.4-C, energized at less than 60,000 volts, where trimming or removal 

is not practicable and the conductor is separated from the tree with suitable 

materials or devices to avoid conductor damage by abrasion and grounding of 

the circuit through the tree. 

2. Rule 35 requirements do not apply where the utility supply or communication 

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company has made a “good faith” effort to obtain permission to trim or remove 

vegetation but permission was refused or unobtainable. A “good faith” effort 

shall consist of current documentation of a minimum of an attempted personal 

contact and a written communication, including documentation of mailing or 

delivery. However, this does not preclude other action or actions from 

demonstrating “good faith”. If permission to trim or remove vegetation is 

unobtainable and requirements of exception 2 are met, the utility company is not 

compelled to comply with the requirements of exception 1. 

3. Whenever a property owner obstructs access to, or fails to make accessible, 

overhead facilities for vegetation management activities, the supply or 

communication company shall not be responsible for the consequences of failing 

to trim or remove such vegetation so long as the supply or communication 

company can document (1) at least one attempted personal contact with the 

owner, (2) at least one written communication to the owner, including 

documentation of mailing or delivery, and (3) notification to Commission Staff.

3. 4. The Commission recognizes that unusual circumstances beyond the control 

of the utility may result in nonconformance with the rules. In such cases, the 

utility may be directed by the Commission to take prompt remedial action to 

come into conformance, whether or not the nonconformance gives rise to 

penalties or is alleged to fall within permitted exceptions or phase–in 

requirements. 

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A-38

Contested Proposal 8A re: GO 95, Rule 35, Appendix E, Table 

(Joint Utilities) 

Proposed Revisions Shown with Strikeout and Underline 

Voltage of Lines

Case 13

of Table 1

Case 14

of Table 1

Radial clearances for any conductor of a line 

operating at 2,400V or more volts, but less than 

72,000 volts V

4 feet 6.5 10 feet

Radial clearances for any conductor of a line 

operating at 72,000V or more volts , but less than 

110,000 volts V

6 feet 10 15 feet 

Radial clearances for any conductor of a line 

operating at 110,000 V or more volts, but less 

than 300,000 volts V

10 feet 20 feet 

Radial clearances for any conductor of a line 

operating at 300,000 or more volts V

15 feet 20 feet 

Contested Proposal 8B re: GO 95, Rule 35, Guidelines (Joint Utilities) 

Proposed Revisions Shown with Strikeout and Underline 

The following are guidelines to Rule 35. 

The radial clearances shown below are recommended minimum clearances that 

should be established, at time of trimming, between the vegetation and the 

energized conductors and associated live parts where practicable. Reasonable 

vegetation management practices may make it advantageous to obtain greater 

clearances than those listed below: to ensure compliance until the next scheduled 

maintenance. Each utility may determine and apply additional appropriate 

clearances beyond clearances listed below, which take into consideration various 

factors, including: line operating voltage, length of span, line sag, planned 

maintenance cycles, location of vegetation within the span, species type, 

experience with particular species, vegetation growth rate and characteristics, 

vegetation management standards and best practices, local climate, elevation, 

and fire risk.

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A-39

Contested Proposal 8C re: GO 95, Rule 35, Guidelines (CFBF and MGRA) 

Proposed Revisions Shown with Strikeout and Underline 

The following are guidelines to Rule 35. 

The radial clearances shown below are recommended minimum clearances that 

should be established, at time of trimming, between the vegetation and the 

energized conductors and associated live parts where practicable. Reasonable 

vegetation management practices may make it advantageous for the purposes of 

public safety, reliability or tree health to obtain greater clearances than those 

listed below: to ensure compliance until the next scheduled maintenance. Each 

utility may determine and apply additional appropriate clearances beyond 

clearances listed below, which take into consideration various factors, including: 

line operating voltage, length of span, line sag, planned maintenance cycles, 

location of vegetation within the span, species type, experience with particular 

species, vegetation growth rate and characteristics, vegetation management 

standards and best practices (including when feasible appropriate tree crop 

production manuals), local climate, elevation, and fire risk.

Contested Proposal 9 re: GO 95, Rule 38, Table 2, Footnote (aaa) 

(Joint Utilities) 

Proposed New Footnote Shown with Underline 

New Footnote “aaa” to clearances specified in Rule 38, Table 2, Cases 1-13: 

(aaa) The vertical separation requirement between conductors in the adjoining 

mid-span may or may not require increased vertical separation at the pole based 

on the sag characteristics of the conductors. 

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A-40

Contested Proposal 10A re: GO 95, Rule 44.4 (CIP Coalition)

Proposed New Rule 44.4 Shown with Underline 

44.4 Cooperation

All entities with facilities on the subject pole shall cooperate with the company 

performing the load calculations necessitated by the provisions of Rule 44.1, 44.2 

or 44.3, including, but not limited to, promptly providing or making reasonably 

available, upon request and to the extent it exists, the following:

(a) The most recent intrusive pole test data;

(b) Any information regarding its facilities necessary to perform a pole 

loading calculation that is not readily available to the company performing the 

pole loading calculations through a field visit; and

(c) A table of standard input values used by the Responding Company in pole 

loading calculations (e.g., standard conductor or cable sizes, tension values, and 

equipment sizes and weights).

In the event a pole attachment application or a joint pole application submitted 

to a pole owner is rejected, the pole owner shall provide the applicant with the 

reason(s) for the rejection with the returned application. In the event a pole 

attachment application or a joint pole application is rejected by a pole owner 

because it has failed to meet the pole loading limitations established by the pole 

owner (consistent with General Order 95 or any subsequent regulation), the pole 

owner should also provide the applicant with sufficient information to 

determine how the pole loading limitations were exceeded with the returned 

application. 

Note: “Promptly” means as soon as practicable but, absent exigent 

circumstances or mutual agreement, no more than fifteen (15) business days 

from the date of the request. (Exigent circumstances include requests for 

intrusive data or other necessary information on transmission poles, or requests 

for information on a large number of poles in a limited time period.) 

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Contested Proposal 10B re: GO 95, Rule 44.2, Rule 44.4, and Appendix I 

(Joint Utilities)

Proposed Revisions to Rules 44.2 and 44.4 Shown with Strikeout and 

Underline. 

Proposed Revisions to Rule 44.2 and Addition of New Rule 44.4 

44.2 Additional Construction 

Any utility entity planning the addition of facilities that materially increase the 

load on a structure shall perform a loading calculation to ensure that the addition 

of the facilities will not reduce the safety factors below the values specified by 

Section IV. Such utility entity shall maintain these pole loading calculations and 

shall provide such information to authorized joint use pole occupants and the 

Commission upon request. 

All other utilities or on the subject pole shall cooperate with the utility 

performing the load calculations described above including, but not limited to, 

providing intrusive pole loading data and other data necessary to perform those 

calculations. 

Note: Nothing contained in this rule shall be construed as allowing the safety 

factor of a facility to be reduced below the required values specified in Rules 44.1 

and 44.3. 

44.4 Cooperation

Entities with facilities on a pole shall cooperate with entities performing pole 

load calculations necessitated by Rules 44.1, 44.2 and 44.3 including, but not 

limited to, providing upon request intrusive pole test results and other data 

necessary to perform those calculations. (See Appendix I)

General Order 95 Appendix I 

Guidelines to Rule 44.4

________________________________________________________________

The following are guidelines to Rule 44.4 

Entities with facilities on a pole should cooperate with the entity 

performing the load calculations necessitated by the provisions of Rule 44.1, 44.2 

or 44.3, including, but not limited to, promptly providing, upon request and if 

available, the following:

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(a) The most recent intrusive pole test data;

(b) Any information regarding its facilities necessary to perform a pole 

loading calculation that is not readily available to the company performing the 

pole loading calculations through a field visit; and

(c) A table of standard input values used by the responding entity in pole 

loading calculations (e.g., standard conductor or cable sizes, tension values, and 

equipment sizes and weights).

“Promptly providing” means as soon as practicable but, absent exigent 

circumstances or mutual agreement, no more than fifteen (15) business days 

from the date of the request. (Exigent circumstances include requests for 

intrusive data or other necessary information on transmission poles, or requests 

for information on a large number of poles in a limited time period.)

In the event a pole attachment application or a joint pole application submitted 

to a pole owner is rejected, the pole owner should provide the applicant with an 

explanation of the reason(s) for the rejection with the returned application. In 

the event a pole attachment application or a joint pole application is rejected by a 

pole owner because it has failed to meet the pole loading limitations established 

by the pole owner (consistent with General Order 95 or any subsequent 

regulation), the pole owner should also provide the applicant with, sufficient 

information to determine how the pole loading limitations were exceeded. 

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A-43

Contested Proposal 11A re: GO 95, Rule 48 (Joint Utilities)

Proposed Revisions to Rule 48 Shown with Strikeout and Underline. 

48 Ultimate Strength of Materials 

Structural members, and their connections, and other elements of overhead lines 

shall be designed and constructed in accordance with the loading criteria 

specified in Rule 43 so that the structures and parts thereof will not fail or be 

seriously distorted at any load less than their maximum working loads 

(developed under the current construction arrangements with loadings as 

specified in Rule 43) and the safety factors specified in Rule 44. 

Values used for the ultimate strength of material shall comply with the safety

factors specified in Rule 44. 

Contested Proposal 11B re: GO 95, Section IV, 

Proposed Ordering Paragraph (CPSD)

Proposed Ordering Paragraph Shown with Underline. 

Proposed Ordering Paragraph: 

The Consumer Protection and Safety Division shall establish a technical working 

group to address possible changes to Section IV of General Order 95. The 

technical working group shall consider appropriate revisions, if any, to Section 

IV of General Order 95 to update the section to incorporate modern materials 

and practices. CPSD shall report back to the Commission within 12 months.

Contested Proposal 12 re: GO 95, Proposed Rule 91.5 (SDG&E) 

Proposed Rule 91.5 Shown with Underline. 

91.5 Marking

Communication cables and conductors shall be marked as to ownership to 

facilitate identification.

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A-44

Contested Proposal 13A re: GO 165, Section V (CPSD and MGRA) 

Proposed New Section V of GO 165 Shown with Underline. 

V. Fire Incident Reporting and Data Collection Requirements

California investor-owned electric utilities shall collect information on all fire 

incidents which are attributable or allegedly attributable to their overhead 

electric distribution lines or transmission lines. Data to be collected per incident 

shall include date, time, general location, specific geographical coordinates, 

equipment, voltage, fire agencies involved, weather conditions, vegetation 

conditions, and apparent cause. Collected data shall be provided electronically 

under General Order 66-C and Section 583 of the Public Utilities Code annually 

to the Director of CPSD or its successor. Summaries of collected data shall be 

provided electronically annually to the Director of CPSD or its successor, which 

may be made available to the public and state or local fire agencies. 

Contested Proposal 13B re: Proposed Ordering Paragraph 

on Data Collection (PG&E) 

Proposed Ordering Paragraph Shown with Underline. 

Proposed Ordering Paragraph: 

Within 6 months of the effective date of this decision, the electric utilities and 

CPSD shall meet and confer regarding electric utility collection and utilization of 

fire-related data. Such discussions shall consider whether CPSD is receiving the 

fire-related data it needs from the electric utilities, and whether it would be 

useful for the electric utilities to collect different and/or additional data that 

would be provided to CPSD and/or fire agencies such as Cal Fire. Within 

9 months of the effective date of this decision, the electric utilities and CPSD shall 

submit a report to the Executive Director of the Commission regarding the 

results of such discussions. State fire agencies shall be invited to participate in 

the discussions and report. These discussions shall be conducted in such a 

manner as to protect the confidentiality of the utilities’ data. 

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A-45

Contested Proposal 14A re: Proposed Ordering Paragraph Regarding 

Fire Maps (CPSD and MGRA) 

Proposed Ordering Paragraph Shown with Underline. 

Proposed Ordering Paragraph 

Investor-owned electric utilities (IOUs) and communication infrastructure

providers (CIPs) shall provide funding to support the development of a working 

plan to determine how to create utility-specific high-resolution maps combining 

wind and vegetation data that identify areas at the greatest risk of catastrophic 

power line wildland fire ignitions. Within 60 days of the issuance of this 

decision, or at a time mutually agreed to by the participating parties, investorowned electric utilities (IOUs) and communication infrastructure providers 

(CIPs) shall meet and confer with CAL FIRE and CPSD staff in order to discuss 

how to create utility-specific high-resolution maps combining wind and 

vegetation data that identify areas at the greatest risk of catastrophic power line 

wildland fire ignitions. The purpose of the maps will be for determining 

inspection and maintenance cycles in all cases where geographic locations and 

maps are referred to in General Orders 95 and 165, and the maps may be used in 

the future to determine geography-specific construction, maintenance, and 

operational standards. The IOUs and CIPs shall cooperate with CAL FIRE and 

CPSD staff to develop a working plan to determine the process by which the 

maps would be produced, estimate the time and costs required to produce and 

maintain maps, devise a proposed revision cycle under which subsequent 

updates to the maps would be undertaken to incorporate changes to the 

underlying data or improvements or changes to analysis techniques, and any 

other actions that the Commission would need to take to enable the creation of 

utility-specific maps, including the use of funding provided by IOUs and CIPs. 

IOUs and CIPs shall further meet and confer with CAL FIRE to determine what 

funding may be required to produce such a working plan. Within six months 

after the issuance of this decision, IOUs and CIPs shall report back to the 

Commission and CPSD staff on the status of the working plan. Upon completion 

of the working plan, the Commission will decide whether to order the investorowned electric utilities and communication infrastructure providers to fund the 

creation and maintenance of utility-specific high-resolution maps. Maps 

adopted in Phase 1 or Phase 2 of this OIR shall remain applicable until further 

order by the Commission. 

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A-46

Contested Proposals 14A and 14B re: GO 95, Rule 31.2, 

Fire Maps for CIP Inspections

Proposed Additions to GO 95, Rule 31.2, Shown with Underline. 

31.2 Inspection of Lines

Note: For the following Southern California counties: Santa Barbara, 

Ventura, Los Angeles, Orange, San Diego, Riverside, and San Bernardino, 

Specified Fire Areas shall be defined as the Extreme and Very High Fire 

Threat Zones as identified in Cal Fire’s Fire and Resource Assessment 

Program Fire Threat Map. For the remaining counties in the State of 

California, Specified Fire Areas are defined as the areas designated as 

Threat Class 3 and 4 identified on Threat Class 3 and 4 Map attached as 

Appendix G, Figure 90. Communication Infrastructure Providers shall 

have the discretion to use their own expertise and judgment to determine 

if local conditions require them to adjust the boundaries of the maps.

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A-47

Figure 90

(END OF APPENDIX A) 

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B-1

Appendix B: Adopted Revisions to 

General Orders 95, 165, and 166

Appendix B shows the text of General Orders 95, 165, and 166 

as revised by today’s decision. 

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B-2

General Order 95, Rule 11 

Adopted Rule in Final Form 

18 Purpose of Rules 

The purpose of these rules is to formulate, for the State of California, 

requirements for overhead line design, construction, and maintenance, the 

application of which will ensure adequate service and secure safety to persons 

engaged in the construction, maintenance, operation or use of overhead lines and 

to the public in general. 

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B-3

General Order 95, Rule 18A

Adopted Rule in Final Form 

This adopted revisions to Rule 18A include the consensus revisions to 

Rule 18A that replace the term “violation” with the term “nonconformance.” 

18 Reporting and Resolution of Safety Hazards Discovered by Utilities 

For purposes of this rule, “Safety Hazard” means a condition that poses a 

significant threat to human life or property. 

“Southern California” is defined as the following: Imperial, Los Angeles, 

Orange, Riverside, Santa Barbara, San Bernardino, San Diego, and Ventura 

Counties. 

“Extreme and Very High Fire Threat Zones” are defined on the Fire and 

Resource Assessment Program (FRAP) Map prepared by the California 

Department of Forestry and Fire Protection or the modified FRAP Map prepared 

by San Diego Gas & Electric Company (SDG&E) and adopted by 

Decision 11-XX—YYY in Phase 2 of Rulemaking 08-11-005. All entities subject to 

Rule 18 shall use the FRAP Map to implement Rule 18, except that SDG&E may 

use its modified FRAP Map to implement Rule 18. 

Part A: Resolution of Safety Hazards and General Order 95 Nonconformances 

(1)(a) Each company (including utilities and CIPs) is responsible for taking 

appropriate corrective action to remedy Safety Hazards and GO 95 

nonconformances posed by its facilities. 

(b) Upon completion of the corrective action, the company’s records shall 

show, with sufficient detail, the nature of the work, the date, and the 

identity of persons performing the work. These records shall be preserved 

by the company for at least ten (10) years and shall be made available to 

Commission staff upon 30 days notice. 

(c) Where a communications company’s or an electric utility’ actions result in 

GO nonconformances for another entity, that entity’s remedial action will 

be to transmit a single documented notice of identified nonconformances 

to the communications company or electric utility for compliance. 

(2)(a) All companies shall establish an auditable maintenance program for their 

facilities and lines. All companies must include a timeline for corrective 

actions to be taken following the identification of a Safety Hazard or 

nonconformances with General Order 95 on the company’s facilities. The 

auditable maintenance program shall prioritize corrective actions 

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consistent with the priority levels set forth below and based on the 

following factors, as appropriate: 

• Safety and reliability as specified in the priority levels below; 

• Type of facility or equipment; 

• Location, including whether the Safety Hazard or nonconformance is 

located in an Extreme or Very High Fire Threat Zone in Southern 

California; 

• Accessibility; 

• Climate; 

• Direct or potential impact on operations, customers, electrical company 

workers, communications workers, and the general public. 

There shall be 3 priority levels. 

(i) Level 1: 

• Immediate safety and/or reliability risk with high probability for 

significant impact. 

• Take action immediately, either by fully repairing the condition, or by 

temporarily repairing and reclassifying the condition to a lower 

priority. 

(ii) Level 2: 

• Variable (non-immediate high to low) safety and/or reliability risk. 

• Take action to correct within specified time period (fully repair, or by 

temporarily repairing and reclassifying the condition to a lower 

priority). 

Time period for correction to be determined at the time of identification 

by a qualified company representative, but not to exceed: 

(1) 12 months for nonconformances that compromise worker safety, 

(2) 12 months for nonconformances that create a fire risk and are 

located in an Extreme or Very High Fire Threat Zone in Southern 

California, and (3) 59 months for all other Level 2 nonconformances. 

(iii) Level 3: 

• Acceptable safety and/or reliability risk. 

• Take action (re-inspect, re-evaluate, or repair) as appropriate. 

(b) Correction times may be extended under reasonable circumstances, such 

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as: 

• Third party refusal 

• Customer issue 

• No access 

• Permits required 

• System emergencies (e.g. fires, severe weather conditions) 

(3) Companies that have existing General Order 165 auditable inspection and 

maintenance programs that are consistent with the purpose of Rule 18A 

shall continue to follow their General Order 165 programs. 

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General Order 95, Rule 18B

Adopted Rule in Final Form 

B. Notification of Safety Hazards 

If a company, while performing inspections of its facilities, discovers a safety 

hazard(s) on or near a communications facility or electric facility involving 

another company, the inspecting company shall notify the other company 

and/or facility owner of such safety hazard(s) no later than 10 business days 

after the discovery. To the extent the inspecting company cannot determine the 

facility owner/operator, it shall contact the pole owner(s), who shall be 

responsible for promptly notifying the company owning/operating the facility 

with the safety hazard(s), normally not to exceed five business days after being 

notified of the safety hazard. The notification shall be documented and such 

documentation must be preserved by all parties for at least ten years. 

Note: Each pole owner must be able to determine all other pole owners on poles 

it owns. Each pole owner must be able to determine all authorized entities that 

attach equipment on its portion of a pole. 

General Order 95, Rule 23.0 

Adopted Rule in Final Form 

Rule 23.0 Reconstruction means that work which in any way changes the 

identity of the pole, tower or structure on which it is performed. A change in 

grade of construction or class of circuit is considered reconstruction. For 

exceptions see Rule 12.1. 

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General Order 95, Rule 31.1

Adopted Rule in Final Form 

31.1 Design, Construction and Maintenance 

Electrical supply and communication systems shall be designed, 

constructed, and maintained for their intended use, regard being given to 

the conditions under which they are to be operated, to enable the furnishing 

of safe, proper, and adequate service. 

For all particulars not specified in these rules, design, construction, and 

maintenance should be done in accordance with accepted good practice for 

the given local conditions known at the time by those responsible for the 

design, construction, or maintenance of communication or supply lines and 

equipment. 

A supply or communications company is in compliance with this rule if it 

designs, constructs, and maintains a facility in accordance with the 

particulars specified in General Order 95, except that if an intended use or 

known local conditions require a higher standard than the particulars 

specified in General Order 95 to enable the furnishing of safe, proper, and 

adequate service, the company shall follow the higher standard. 

For all particulars not specified in General Order 95, a supply or 

communications company is in compliance with this rule if it designs, 

constructs and maintains a facility in accordance with accepted good 

practice for the intended use and known local conditions. 

All work performed on public streets and highways shall be done in such a 

manner that the operations of other utilities and the convenience of the 

public will be interfered with as little as possible and no conditions 

unusually dangerous to workmen, pedestrians or others shall be established 

at any time. 

Note: The standard of accepted good practice should be applied on a case 

by case basis. For example, the application of “accepted good practice” may 

be aided by reference to any of the practices, methods, and acts engaged in 

or approved by a significant portion of the relevant industry, or which may 

be expected to accomplish the desired result with regard to safety and 

reliability at a reasonable cost. 

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General Order 95, Rule 31.2

Adopted Rule in Final Form 

31.2 Inspection of Lines

Lines shall be inspected frequently and thoroughly for the purpose of 

ensuring that they are in good condition so as to conform with these rules. 

Lines temporarily out of service shall be inspected and maintained in such 

condition as not to create a hazard. 

A. Communication Lines (See Rule 80.1) 

B. Supply Lines shall be inspected in compliance with the requirements 

of General Order 165. 

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General Order 95, Rule 35

Adopted Rule in Final Form 

35 Vegetation Management

Where overhead conductors traverse trees and vegetation, safety and reliability 

of service demand that certain vegetation management activities be performed in 

order to establish necessary and reasonable clearances, the minimum clearances 

set forth in Table 1, Cases 13 and 14, measured between line conductors and 

vegetation under normal conditions shall be maintained. (Also see Appendix E 

for tree trimming guidelines.) These requirements apply to all overhead 

electrical supply and communication facilities that are covered by this 

General Order, including facilities on lands owned and maintained by California 

state and local agencies. 

When a supply or communication company has actual knowledge, obtained 

either through normal operating practices or notification to the company, that 

dead, rotten or diseased trees or dead, rotten or diseased portions of otherwise 

healthy trees overhang or lean toward and may fall into a span of supply or 

communication lines, said trees or portions thereof should be removed. 

Communication and electric supply circuits, energized at 750 volts or less, 

including their service drops, should be kept clear of vegetation in new 

construction and when circuits are reconstructed or repaired, whenever 

practicable. When a supply or communication company has actual knowledge, 

obtained either through normal operating practices or notification to the 

company, that its circuit energized at 750 volts or less shows strain or evidences 

abrasion from vegetation contact, the condition shall be corrected by reducing 

conductor tension, rearranging or replacing the conductor, pruning the 

vegetation, or placing mechanical protection on the conductor(s). For the 

purpose of this rule, abrasion is defined as damage to the insulation resulting 

from the friction between the vegetation and conductor. Scuffing or polishing of 

the insulation or covering is not considered abrasion. Strain on a conductor is 

present when vegetation contact significantly compromises the structural 

integrity of supply or communication facilities. Contact between vegetation and 

conductors, in and of itself, does not constitute a nonconformance with the rule. 

EXCEPTIONS: 

1. Rule 35 requirements do not apply to conductors, or aerial cable that complies 

with Rule 57.4-C, energized at less than 60,000 volts, where trimming or 

removal is not practicable and the conductor is separated from the tree with 

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suitable materials or devices to avoid conductor damage by abrasion and 

grounding of the circuit through the tree. 

2. Rule 35 requirements do not apply where the supply or communication 

company has made a “good faith” effort to obtain permission to trim or 

remove vegetation but permission was refused or unobtainable. A “good 

faith” effort shall consist of current documentation of a minimum of an 

attempted personal contact and a written communication, including 

documentation of mailing or delivery. The written communication may 

include a statement that the company may seek to recover any costs and 

liabilities incurred by the company due to its inability to trim or remove 

vegetation. However, this does not preclude other action or actions from 

demonstrating “good faith”. If permission to trim or remove vegetation is 

unobtainable and requirements of exception 2 are met, the company is not 

compelled to comply with the requirements of exception 1. 

3. The Commission recognizes that unusual circumstances beyond the control of 

the utility may result in nonconformance with the rules. In such cases, the 

utility may be directed by the Commission to take prompt remedial action to 

come into conformance, whether or not the nonconformance gives rise to 

penalties or is alleged to fall within permitted exceptions or phase–in 

requirements. 

4. Mature trees whose trunks and major limbs are located more than six inches, 

but less than the clearance required by Table 1, Cases 13E and 14E, from 

primary distribution conductors are exempt from the minimum clearance 

requirement under this rule. The trunks and limbs to which this exemption 

applies shall only be those of sufficient strength and rigidity to prevent the 

trunk or limb from encroaching upon the six–inch minimum clearance under 

reasonably foreseeable local wind and weather conditions. The utility shall 

bear the risk of determining whether this exemption applies, and the 

Commission shall have final authority to determine whether the exemption 

applies in any specific instance, and to order that corrective action be taken in 

accordance with this rule, if it determines that the exemption does not apply. 

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General Order 95, Rule 35, Appendix E, Guidelines

Adopted Revisions to GO 95, Appendix E in Final Form 

The following are guidelines to Rule 35. 

The radial clearances shown below are recommended minimum clearances that 

should be established, at time of trimming, between the vegetation and the 

energized conductors and associated live parts where practicable. Reasonable 

vegetation management practices may make it advantageous for the purposes of 

public safety or service reliability to obtain greater clearances than those listed 

below to ensure compliance until the next scheduled maintenance. Each utility 

may determine and apply additional appropriate clearances beyond clearances 

listed below, which take into consideration various factors, including: line 

operating voltage, length of span, line sag, planned maintenance cycles, location 

of vegetation within the span, species type, experience with particular species, 

vegetation growth rate and characteristics, vegetation management standards 

and best practices, local climate, elevation, fire risk, and vegetation trimming 

requirements that are applicable to State Responsibility Area lands pursuant to 

Public Resource Code Sections 4102 and 4293. 

General Order 95, Rule 35, Appendix E, Table

Adopted Rule in Final Form 

Voltage of Lines Case 13

of Table 1

Case 14

of Table 1

Radial clearances for any conductor of a line 

operating at 2,400 V or more, but less than 

72,000 V

4 feet 6.5 feet

Radial clearances for any conductor of a line 

operating at 72,000 V or more, but less than 

110,000 V

6 feet 10 feet

Radial clearances for any conductor of a line 

operating at 110,000 V or more, but less than 

300,000 V

10 feet 20 feet 

Radial clearances for any conductor of a line 

operating at 300,000 V 15 feet 20 feet 

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General Order 95, Rule 37, Table 1, Case 14 and Footnotes (fff) -(jjj)

Adopted Rule in Final Form 

Table 1: Basic Minimum Allowable Vertical Clearance of Wires above Railroads, Thoroughfares, Ground or 

Water Surfaces; Also Clearances from Poles, Buildings, Structures or Other Objects (nn) (Letter 

References Denote Modifications of Minimum Clearances as Referred to in Notes Following This 

Table)

 Wire of Conductor Concerned 

Case 

No. 

Nature of 

Clearance 

A 

Span Wires 

(Other than 

Trolley 

Span 

Wires) 

Overhead 

Guys and 

Messenger

s 

B 

Communication

s Conductors 

(including Open 

Wire, Cables and 

Service Drops) 

Supply Service 

Drops of 0-750 

Volts 

C 

Trolley 

Contact 

Feeder 

and 

Span 

Wires, 

0-5,000 

Volts 

D 

Supply 

Conductors 

of 0-750 

Volts and 

Supply 

Cable 

Treated as 

in Rule 

57.8 

E 

Supply 

Conductors 

and Supply 

Cables, 

750-22,500 

Volts 

F 

Supply 

Conductors 

And 

Supply 

Cables, 

22.5-300 kV

G 

Supply 

Conductors 

and Supply 

Cables, 

300-550 

kV(mm) 

14 

Radial 

clearance of 

bare line 

conductors 

from 

vegetation in 

Extreme and 

Very High 

Fire Threat 

Zones in 

Southern 

California 

(aaa) (ddd) 

(hhh)(jjj)

 

18 

inches 

(bbb) 

48 inches 

(bbb) (iii)

48 inches 

(fff)

120 inches 

(ggg) 

(fff) Clearances in this case shall be increased for conductors operating above 72 kV, to the following: 

1. Conductors operating between 72 kV and a 110 kV shall maintain a 72 inch clearance. 

2. Conductors operating above 110 kV shall maintain a 120 inch clearance. 

(ggg) Shall be increased by 0.40 inch per kV in excess of 500 kV. 

(hhh) Extreme and Very High Fire Threat Zones are defined by California Department of Forestry and Fire Protection’s 

Fire and Resource Assessment Program (FRAP) Fire Threat Map. The FRAP Fire Threat Map is to be used to 

establish approximate boundaries for purposes of this rule. The boundaries of the map are to be broadly 

construed, and utilities should use their own expertise and judgment to determine if local conditions require them 

to adjust the boundaries of the map. Southern California shall be defined as the following: Imperial, Los Angeles, 

Orange, Riverside, Santa Barbara, San Bernardino, San Diego, and Ventura Counties. 

(iii) May be reduced to 18 inches for conductors operating less than 2.4 kV. 

(jjj) Clearances in this case shall not apply to orchards of fruit, nut or citrus trees that are plowed or cultivated. In those 

areas Case 13 clearances shall apply. 

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General Order 95, Rules 44.1, 44.2, 44.3 

Adopted Rules in Final Form 

44.1 Installation and Reconstruction 

Lines and elements of lines upon installation or reconstruction, shall provide as a 

minimum the safety factors specified in Table 4 for vertical loads and loads 

transverse to lines and for loads longitudinal to lines except where longitudinal 

loads are balanced or where there are changes in grade of construction (see 

Rules 47.3, 47.4 and 47.5). The design shall consider the structural loading and 

mechanical strength requirements of all supply and communication facilities 

planned to occupy the structure. For purposes of this rule, the term “planned” 

applies to the facilities intended to occupy the structure that are actually known 

to the constructing company at the time of design. 

44.2 Additional Construction 

Any entity planning the addition of facilities that materially increase vertical, 

transverse or longitudinal loading on a structure shall perform a loading 

calculation to ensure that the addition of the facilities will not reduce the safety 

factors below the values specified by Rule 44.3. Such entity shall maintain these 

pole loading calculations for ten years and shall provide such information to 

authorized joint use pole occupants and the Commission upon request. 

Note: For the purpose of Rule 44.2, a material increase in load is an addition 

which increases the load on a structure by more than five percent per 

installation, or ten percent over a 12-month span, of the electric utility’s or 

Communication Infrastructure Provider’s current load. 

44.3 Replacement 

Lines or parts thereof shall be replaced or reinforced before safety factors have 

been reduced (due to deterioration and/or installation of additional facilities) in 

Grades “A” and “B” construction to less than two-thirds of the construction 

safety factors specified in Rule 44.1 and in Grades “C” and “F” construction to 

less than one-half of the construction safety factors specified in Rule 44.1. Poles 

in Grade “F” construction shall also conform to the requirements of Rule 81.3-A. 

In no case shall the application of this rule be held to permit the use of structures 

or any member of any structure with a safety factor less than one. 

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General Order 95, Rule 44.4

Adopted Rule in Final Form 

44.4 Cooperation 

All entities with facilities on the subject pole shall cooperate with the company 

performing the load calculations necessitated by the provisions of Rule 44.1, 44.2 

or 44.3, including, but not limited to, promptly providing or making reasonably 

available, upon request and to the extent it exists, the following: 

a. The most recent intrusive pole test data; 

b. Any information regarding its facilities necessary to perform a 

pole loading calculation that is not readily available to the 

company performing the pole loading calculations through a 

field visit; and 

c. A table of standard input values used by the Responding 

Company in pole loading calculations (e.g., standard conductor 

or cable sizes, tension values, and equipment sizes and weights). 

In the event a pole attachment application or a joint pole application submitted 

to a pole owner is rejected, the pole owner shall provide the applicant with the 

reason(s) for the rejection with the returned application. In the event a pole 

attachment application or a joint pole application is rejected by a pole owner 

because it has failed to meet the pole loading limitations established by the pole 

owner (consistent with General Order 95 or any subsequent regulation), the pole 

owner should also provide the applicant with sufficient information to 

determine how the pole loading limitations were exceeded with the returned 

application. 

Note: “Promptly” means as soon as practicable but, absent exigent 

circumstances or mutual agreement, no more than fifteen (15) business days 

from the date of the request. (Exigent circumstances include requests for 

intrusive data or other necessary information on transmission poles, or requests 

for information on a large number of poles in a limited time period.) 

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General Order 95, Rule 80.1A 

Adopted Rule in Final Form 

80.1 Inspection Requirements for Communication Lines: 

A. Patrol and Detailed Inspections 

(1) Inspection Requirements for Joint-Use Poles in High Fire-Threat Areas 

In high fire-threat areas, the inspection intervals for (i) Communication Lines 

located on Joint-Use Poles (See Rule 21.8) that contain Supply Circuits (See 

Rule 20.6-D), and (ii) Communication Lines attached to a pole that is within 

three spans of a Joint-Use Pole with Supply Circuits, shall not exceed the time 

specified in the following Table. 

Inspection Northern California Southern California 

Patrol 2 Years 1 Year 

Detailed 10 Years 5 Years 

Inspection intervals and shall be conducted more frequently than shown in the 

above table, if necessary, based on the five factors listed in Rule 80.1(A)(2), 

below. 

For the purpose of the above Table, the high fire-threat areas in Southern 

California are Extreme and Very High Fire Threat Zones in the following 

counties: Imperial, Los Angeles, Orange, Riverside, Santa Barbara, 

San Bernardino, San Diego, and Ventura. Extreme and Very High Fire Threat 

Zones are defined by California Department of Forestry and Fire Protection’s 

Fire and Resource Assessment Program (FRAP) Fire Threat Map. 

For the purpose of the above Table, the high fire-threat areas in Northern 

California are areas designated as Threat Classes 3 and 4 on the Reax Map 

adopted by Decision 11-XX-YYY issued in Phase 2 of Rulemaking 08-11-005. 

For the purpose of implementing the patrol and detailed inspection intervals in 

the above Table in the high fire-threat areas of the state, the term “year” is 

defined as 12 consecutive calendar months starting the first full calendar month 

after an inspection is performed, plus or minus two full calendar months, not 

to exceed the end of the calendar year in which the next inspection is due. 

The FRAP Map and Reax Map are to be used to establish approximate 

boundaries. Communications Infrastructure Providers should use their own 

expertise and judgment to determine if local conditions require them to adjust 

the boundaries of the map. 

Inspections in high fire-threat areas shall be planned and conducted in 

accordance with the statewide inspection requirements and procedures 

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described in Rule 80.1.A(2), below. 

Each company’s procedures shall describe (i) the methodology used to ensure 

that all Communication Lines are subject to the required inspections, and 

(ii) the procedures used for specifying what problems should be identified by 

the inspections. The procedures used for specifying what problems should be 

identified by the inspections shall include a checklist for patrol inspections. 

(2) Statewide Inspection Requirements 

Each company shall prepare, follow, and modify as necessary, procedures for 

conducting patrol or detailed inspections for all of its Communication Lines 

throughout the State. Consistent with Rule 31.2, the type, frequency and 

thoroughness of inspections shall be based upon the following factors: 

• Fire threat 

• Proximity to overhead power-line facilities 

• Terrain 

• Accessibility 

• Location 

Each company that discovers a safety hazard on or near a communications 

facility or electric facility involving another company while performing 

inspections of its own facilities pursuant to this rule shall notify the other 

company and/or facility owner of such safety hazard in accordance with 

Rule 18(B). 

Each company’s procedures shall describe (i) the methodology used to ensure 

that all Communication Lines are subject to the required inspections, and 

(ii) the procedures used for specifying what problems should be identified by 

the inspections. The procedures used for specifying what problems should be 

identified by the inspections shall include a checklist for patrol inspections. 

(3) Definitions 

Detailed Inspections. For the purpose of this rule, Detailed Inspection shall be 

defined as a careful visual inspection of Communication facilities and 

structures using inspection tools such as binoculars and measuring devices, as 

appropriate. Detailed inspections may be carried out in the course of other 

company business. 

Patrol Inspections. For the purpose of this rule, Patrol Inspection shall be 

defined as a simple visual inspection, of applicable communications facilities 

equipment and structures that is designed to identify obvious structural 

problems and hazards. Patrol inspections may be carried out in the course of 

other company business. 

(4) Record Keeping 

Each company shall maintain records for at least ten (10) years that provide the 

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following information for each facility subject to this rule: The location of the 

facility, the date of each inspection of the facility, the results of each inspection, 

the personnel who performed each inspection, the date and description of each 

corrective action, and the personnel who performed each correction action. 

Commission staff shall be permitted to inspect records consistent with Public 

Utilities Code Section 314 (a). 

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General Order 95, Rule 80.1B 

Adopted Rule in Final Form 

80.1 Inspection Requirements for Communication Lines: 

B. Intrusive Inspections 

Wood poles in high fire-threat areas that support only Communication 

Lines or equipment shall be intrusively inspected in accordance with 

the schedule established in General Order 165 if they are: 

• Interset between joint-use poles supporting supply lines in the high 

fire-threat areas of Southern California. 

• Within three spans of a joint-use pole supporting supply lines in the 

high fire-threat areas of Southern California. 

• Within one span of a joint-use pole supporting supply lines in the 

high fire-threat areas of Northern California. 

For the purpose of this rule, the high fire-threat areas in Southern 

California are Extreme and Very High Fire Threat Zones in the 

following counties: Imperial, Los Angeles, Orange, Riverside, Santa 

Barbara, San Bernardino, San Diego, and Ventura. Extreme and Very 

High Fire Threat Zones are defined by California Department of 

Forestry and Fire Protection’s Fire and Resource Assessment Program 

(FRAP) Fire Threat Map. The high fire-threat areas in Northern 

California are areas designated as Threat Classes 3 and 4 on the 

Reax Map adopted in Decision 11-XX-YYY issued in Phase 2 of 

Rulemaking 08-11-005. 

The FRAP Fire Threat Map and Reax Map are to be used to establish 

approximate boundaries. Communications Infrastructure Providers 

(CIPs) should use their own expertise and judgment to determine if 

local conditions require them to adjust the boundaries of the map. 

Note: For the purpose of this rule, Intrusive Inspections are defined as 

an inspection involving movement of soil, and/or using more 

sophisticated diagnostic tools beyond visual inspections or instrument 

reading. 

CIPs shall maintain records for the life of the pole that provide the 

following information for each wood pole subject to this rule: The 

location of the pole, the date of each intrusive inspection, the results of 

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each inspection, the personnel who performed each intrusive 

inspections, the date and description of each corrective action, and the 

personnel who performed each correction action. Commission staff 

may inspect records consistent with Public Utilities Code Section 

314(a). 

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General Order 95, Rule 91.5

Adopted Rule 91.5 in Final Form 

91.5 Marking 

Each communication cable and conductor as defined by Rules 20.4, 20.6(A), 20.9, 

84.1, 87.4(C), and 89.1 that is attached to a joint-use pole shall be marked as to 

ownership. The marker shall (1) identify the owner of the cable and/or 

conductor; (2) provide a 24 hour contact number for emergencies or information; 

(3) be made of weather and corrosion resistant material; and (4) be clearly visible 

to workers who climb the pole or ascend by mechanical means. This marking 

requirement applies only to (A) new construction, (B) reconstruction of facilities, 

and (C) existing aerial communication cables and conductors that a technician 

works on when the technician ascends the joint-use pole for regular 

maintenance. 

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General Order 165, Sections I - IV 

Adopted Rule in Final Form 

Appendix A 

Public Utilities Commission of the State of California 

Inspection Requirements for Electric Distribution and Transmission 

Facilities 

__________________________________________________________________________ 

Adopted March 31, 1997 Effective March 1, 1997 

(D.97-03-070 in I.95-02-015 and R.96-11-004) 

Amended August 20, 2009 

(D.09-08-029 in R.08-11-005) 

___________________________________________________________________________________________________________________

I. Purpose 

The purpose of this General Order is to establish requirements for electric 

distribution and transmission facilities (excluding those facilities contained in a 

substation) regarding inspections in order to ensure safe and high-quality electrical 

service. 

II. Applicability 

This General Order applies to all electric distribution and transmission facilities 

(excluding those facilities contained in a substation) that come within the jurisdiction 

of this Commission, located outside of buildings, including electric distribution and 

transmission facilities that belong to non-electric utilities. 

The requirements of this order are in addition to the requirements imposed upon 

utilities under General Orders 95 and 128 to maintain a safe and reliable electric 

system. Nothing in this General Order relieves any utility from any requirements or 

obligations that it has under General Orders 95 and 128. 

This General Order does not apply to facilities of communication infrastructure 

providers. 

III. Distribution Facilities 

A Definitions 

For the purpose of this General Order, 

1 "Urban" shall be defined as those areas with a population of more than 

1,000 persons per square mile as determined by the United States Bureau of 

the Census. 

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2 "Rural" shall be defined as those areas with a population of less than 1,000 

persons per square mile as determined by the United States Bureau of the 

Census. 

3 "Patrol inspection" shall be defined as a simple visual inspection, of 

applicable utility equipment and structures, that is designed to identify 

obvious structural problems and hazards. Patrol inspections may be carried 

out in the course of other company business. 

4 "Detailed" inspection shall be defined as one where individual pieces of 

equipment and structures are carefully examined, visually and through use of 

routine diagnostic test, as appropriate, and (if practical and if useful 

information can be so gathered) opened, and the condition of each rated and 

recorded. 

5. "Intrusive" inspection is defined as one involving movement of soil, taking 

samples for analysis, and/or using more sophisticated diagnostic tools 

beyond visual inspections or instrument reading. 

6 "Corrective Action" shall be defined as maintenance, repair, or replacement 

of utility equipment and structures so that they function properly and safely. 

B Standards for Inspection 

Each utility subject to this General Order shall conduct inspections of its 

distribution facilities, as necessary, to ensure reliable, high-quality, and safe 

operation, but in no case may the period between inspections (measured in 

years) exceed the time specified in Table 1. 

 C Record Keeping 

The utility shall maintain records for (1) at least ten (10) years of patrol and 

detailed inspection activities, and (2) the life of the pole for intrusive 

inspection activities. Such records shall be made available to parties or 

pursuant to Commission rules upon 30 days notice. Commission staff shall be 

permitted to inspect such records consistent with Public Utilities Code 

Section 314 (a). 

For all inspections records shall specify the circuit, area, facility or equipment 

inspected, the inspector, the date of the inspection, and any problems (or items 

requiring corrective action) identified during each inspection, as well as the 

scheduled date of corrective action. 

D Reporting 

By July 1st each utility subject to this General Order shall submit an annual 

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report for the previous year under penalty of perjury. 

The report shall list four categorical types of inspections: Patrols, Overhead 

Detailed, Underground Detailed and Wood Pole Intrusive. The report shall 

denote the total units of work by inspection type for the reporting period and 

the number of outstanding (not completed) inspections within the same 

reporting period for each of the four categories. 

Sample Report Template: 

Type of Inspections 

(1) 

Due (2) Outstanding (3) 

Patrols xxx xxx 

OH Detailed xxx xxx 

UG Detailed xxx xxx 

Wood Pole Intrusive xxx xxx 

Notes: 

1) Each utility will define its reporting unit basis (e.g., circuit, grid, facility / equipment). 

2) Total inspections due in the reporting period. (Does not include outstanding inspections 

from prior years.) 

3) Total inspections required that were not completed in the reporting period. (Does not 

include outstanding inspections from prior years.) 

IV. Transmission Facilities 

Each utility shall prepare and follow procedures for conducting inspections and 

maintenance activities for transmission lines. 

Each utility shall maintain records of inspection and maintenance activities. 

Commission staff shall be permitted to inspect records and procedures consistent 

with Public Utilities Code Section 314 (a). 

/s/ Paul Clanon

Paul Clanon

Executive Director

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Appendix A 

Table 1 

Distribution Inspection Cycles (Maximum Intervals in Years)

Patrol Detailed Intrusive 

Urban Rural Urban Rural Urban Rural

Transformers

Overhead 1 21 5 5 --- --- 

Underground 1 2 3 3 --- --- 

Padmounted 1 2 5 5 --- --- 

Switching/Protective Devices

Overhead 1 21 5 5 --- --- 

Underground 1 2 3 3 --- --- 

Padmounted 1 2 5 5 --- --- 

Regulators/Capacitors 

Overhead 1 21 5 5 --- --- 

Underground 1 2 3 3 --- --- 

Padmounted 1 2 5 5 --- --- 

 

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Overhead Conductor and Cables 1 21

 5 5 --- --- 

Streetlighting 1 2 X x --- --- 

Wood Poles under 15 years 1 2 X x --- --- 

Wood Poles over 15 years which have 

not been subject to intrusive inspection 1 2 X x 10 10 

Wood poles which passed intrusive 

inspection --- --- --- --- 20 20 

(1) Patrol inspections in rural areas shall be increased to once per year in Extreme 

and Very High Fire Threat Zones in the following counties Imperial, Los Angeles, 

Orange, Riverside, Santa Barbara, San Bernardino, San Diego, and Ventura. Extreme 

and Very High Fire Threat Zones are designated on the Fire and Resource 

Assessment Program (FRAP) Map prepared by the California Department of 

Forestry and Fire Protection or the modified FRAP Map prepared by San Diego Gas 

& Electric Company (SDG&E) and adopted by Decision 11-XX—YYY in Phase 2 of 

Rulemaking 08-11-005. The fire-threat map is to be used to establish approximate 

boundaries and Utilities should use their own expertise and judgment to determine 

if local conditions require them to adjust the boundaries of the map. 

Note: This General Order does not apply to cathodic protection systems associated 

with natural gas facilities. 

Note: For the purpose of implementing the patrol and detailed inspection intervals 

in Table 1 above, the term “year” is defined as 12 consecutive calendar months 

starting the first full calendar month after an inspection is performed, plus or minus 

two full calendar months, not to exceed the end of the calendar year in which the 

next inspection is due. 

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General Order 166, Standard 1.E

Adopted Rule in Final Form 

E. Fire Prevention Plan 

Those electric utilities identified below shall have a Fire Prevention Plan that 

describes the measures the electric utility intends to implement, both in the 

short run and in the long run, to mitigate the threat of power-line fire 

ignitions in situations that meet all of the following criteria: (i) The force of 

3-second wind gusts exceeds the maximum working stress specified in 

General Order 95, Section IV, for installed overhead electric facilities; (ii) the 

installed overhead electric facilities affected by these 3-second wind gusts are 

located in geographic areas designated as the first or second highest fire 

threat area on a fire-threat map adopted by the Commission in Rulemaking 

(R.) 08-11-005; and (iii) the 3-second wind gusts occur at the time and place of 

a Red Flag Warning issued by United States National Weather Service. The 

requirement to prepare a fire-prevention plan applies to: (1) Electric utilities 

in Imperial, Los Angeles, Orange, Riverside, Santa Barbara, San Bernardino, 

San Diego, and Ventura counties; and (2) electric utilities in all other counties 

with overhead electric facilities located in areas of high fire risk as determined 

by such utilities in accordance with Decision 11-XX-YYY issued in Phase 2 of 

R.08-11-005. 

Note: The existing GO 166 Standards 1.E (Safety Considerations) through 1.I 

(Plan Update) are renumbered Standards 1.F through 1.J. 

(END OF APPENDIX B) 

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Appendix C: Adopted Interim Fire-Threat Maps 

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1

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2

(END OF APPENDIX C) 

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