HomeMy WebLinkAbout _ 4.5(a)--Approve AMAG Technologies Sole-Source Procurement GI �" Y C� F
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REPORT TO THE CITY COUNCIL
MEETING DATE: August 19, 2025 FROM: Nick Zettel, Director of
ITEM NO. 4.5(a) Redding Electric Utility
***APPROVED BY***
nzettel@cityofredding.org btippin@cityofredding.org
SUBJECT: 4S(a)--Approve AMAG Technologies Sole-Source Procurement
Recommendation
Approve the sole-source procurement of American Magnetics Technologies physical access
control system for use at Redding Electric Utility substations.
Fiscal Impact
There is no fiscal impact associated with the approval of this sole-source request. The planned
substation installations were approved in the Fiscal Year 2023-25 Biennial Budget for Substation
Security capital outlay requests.
Alterna�ive Action
The City Council (Council) could choose not to authorize the sole-source procurement of the
American Magnetics (AMAG) Technologies access control system for Redding Electric Utility's
(RE� substations and provide alternative direction to staff.
Background/Analysis
Physical access control systems regulate secure entry to sensitive sites through card-based
credentialing and centralized monitoring. In alignment with the Utility Security Plan adopted by
Council, REU staff recommends standardizing on the AMAG Technologies platform, which is
already deployed at medium-impact facilities such as the Redding Power Control Center and
Power Plant, and approved for use in other City departments. This standardization reduces
integration complexity, streamlines technical support, and lowers total cost of ownership.
On December 21, 2021, Council approved a sole-source procurement of the Avigilon system;
however, subsequent evaluation revealed it did not meet North American Electric Reliability
Corporation medium-impact facility security standards applicable to REU.
On September 6, 2022, Council authorized procurement of a new access control system, leading
to the selection of AMAG Teehnologies for medium-impact facilities.
Report to Redding City Council July 25, 2025
Re: 4.5(a)--Approve AMAG Technologies Sole-Source Procurement Page 2
Under Public Contract Code (PCC) 3400(c)(2), the Council may make a fmding for a specific
technology to maintain compatibility across City systems. Sole-sourcing AMAG for substations
avoids costs and operational disruption associated with deploying disparate platforms.
Based on REU's successful experience with AMAG, staff recommends sole-source procurement
for low-impact substations to ensure consistent security standards and operational efficiency.
Envir�onmental Review
This activity is not a project as defined by the California Environmental Quality Act, and no
further action is required.
Council Priority/City Manager Goals
� Government of the 215t Century — `Be relevant and proactive to the opportunities and
challenges of today's residents and workforce. Anticipate the future to make better decisions
today."
Attachments
Previous Staff Report 4.3(a) - September 6, 2022 - TO_TOP Medium Impact Access Control
System
Utility Security Plan (Sensitive Info Redacted)
Previous Staff Report - December 21, 2021 -4.3(a) Access Control Sole-Source (Avigilon)
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REPORT TO T�IE CITY COUNCIL
MEETING DATE: September 6, 2022 FROM: Tony Van Boekel, Chief
ITEM NO. 4.3(a) Information Officer/IT
Director
***APPROVED BY***
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tvanboekel@cityofredding.org btippin@cityofredding.org
SUBJECT: 4.3(a)--Transmission Owner and Transmission Operator (TO/TOP) Medium
Im act Access Control S stem
Recommendation
Authorize the City Manager or designee, to approve the procurement of a new access control
system for Redding Electric Utility locations deemed as medium impact locations, based on
standards as set forth by North American Electric Reliability Corporation (NERC), in a not to
exceed amount of$60,000.
Fiscal Impact
Redding Electric Utility (REU) will procure a new access control system for the secured areas
that meets the medium impact standards set forth by NERC. Selection of the replacement system
will be based on its ability to meet NERC requirements, availability, and City of Redding
Purchasing Department approvaL The cost of the new system is anticipated not to exceed
$60,000. Staff will repurpose the existing system at other City facilities to help offset costs.
Alternative Action
The City Council (Council) could choose to not authorize the system change at the secured
facilities and provide alternative direction to staff.
Background/flnalysis
On February 7, 2020, NERC directed REU� to register as a Transmission Owner and
Transmission Operator (TO/TOP). Since that time, REU has worked closely with the Western
Electricity Coordinating Council (WECC) in order to implement and comply with 147 new
standards before the final deadline of November 2022.
Report to Redding City Council August 30, 2022
Re; 4,3(a)--TO/TOP Medium ImpactAccess Control System Page 2
Due to the number of new standards and strict timeline, REU requested approval for the Council
to grant the City Manager, or designee, the authority to sole-source the procurement of software,
hardware, and service agreements relating to REU's operations as a TO/TOP registration based
on recommendations by the expert consultants assisting with the implementation. This reguest
was approved at the March 16, 2021, Council meeting.
One of the new standards requires a physical access control system to be implemented at any
REU medium impact facility. In early October 2021, the City of Redding (City) issued a
Purchase Order for an access control system (Avigilon Access Control Manager (ACM)) using
the aforementioned sole-source authorization, understanding of the standard reguirements at that
time, and vendor information stating they were compliant with NERC standards. The installation
of the access control system was completed in February 2022.
Since that time, it has been discovered that there are two reguirements specific to NERC medium
standards, that Avigilon ACM cannot, and will not, accommodate. As such, a new system is
required in order to fully comply with the NERC medium standard prior to November 2022.
Failure to do so could result in a fine of$1.6 million dollars per day,per offense.
Since the Council approved the City to sole-source the Avigilon ACM as a City-wide sol�ution
for current and future physical access control needs on December 21, 2022, the City will be able
to repurpose the equipment from the secure facilities to other City locations/facilities. Avigilon
ACM is compliant with DOJ, NERC low standards, and can meet the needs of the majority of
the City. The Information Technology Department wi11 work to standardize on the Avigilon
ACM with the exception of facilities where the system is deemed non-compliant based on
supplemental governing regulations or standards.
Envi�onmental Review
This is not a project defined under the California Environmental Quality Act, and no further
action is required
Council PNiority/City Manage� Goals
This is a routine operational item.
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A. Goal of Utility Security Plan......................................................................................................................4
B. Description of Redding Electric Utility........................... ..................4
..................................................
C. Results of Utility Security Plan Assessment ........................................................................................5
II. Background................................................................................................................................................6
III. Plan Development Process......................................................................................................................8
A. Physical Security Principles..................................................................................................................8
B. Utility Security Plan Development Pracess.......................................................................................9
Step 1: Assessment/Plan Development.................................................................................................9
Step 1 A: Identify Covered Distribution Facilities ..................................................................................9
Step 1 B: Perfarm Risk Assessment..........................................................................................................10
Step 1 C: Develop Mitigation Plan........................................................................................................10
Step2: Independent Review.................................................................................................................1 1
Step3: Validation ....................................................................................................................................12
Step4: Adoptian......................................................................................................................................12
Step5: Maintenance..............................................................................................................................12
Step6: Repeat Process...........................................................................................................................12
IV. Identification of Covered Distribution Faciliites (Step 1 A) ...............................................................13
A. Identification Factors .........................................................................................................................13
B, Identification Analysis ........................................................................................................................14
V. Risk Assessment (Step 1 B) .......................................................................................................................15
A. Methodology.......................................................................................................................................15
B. Mitigation Measures...........................................................................................................................15
C. Risk Assessment....................................................................................................................................l b
Redding Electric Utility Security Plan
June 1, 2021
VI. Covered Distributian Facility Mitigation Plans (Step 1 C�..................................................................19
VII. Independent Evaluation and Response (Step 2)..............................................................................19
A. Requirements for Qualified Third-Party Review.............................................................................19
B, Identification of Third-Party Reviewer.............................................................................................19
C. Public ResUlts of Third-Party EvalUation...........................................................................................19
D. REU Response ......................................................................................................................................19
VIII. Validation (Step 3�...................................................................................................................................20
A. Selection of Qualified Authority.......................................................................................................20
B. Results of Qualified Authority Review..............................................................................................20
IX. Narrative Descriptions for Utility Security Plan....................................................................................21
A. Asset Management Program...........................................................................................................21
B. Workforce Training ar�d Retention Program..................................................................................21
C. Preventative Maintenance Plan......................................................................................................21
D. Physical Security Event Training.......................................................................................................22
E. Communication Infrastructure Risk Assessment...........................................................................22
F. Facility Design Features.....................................................................................................................22
APPENQICIES
A. CALIFORNIA PUBLIC UTI�ITIES COMISSION RULEMAKING 15-06-009
B. TNIRD-PARTY EVALUATION OF UTILITY SECURITY MITIGATION PLAN
C. VALIDATION OF UTILITY SECURITY PLAN
D. SUBSTATIC�N MAP
E. REU WILDFIRE MITIGATION PLAN TECHNO�OGY SO�UTIONS PROGRAM
F. REU CRITICAL LOADS AND ALTERNATE CIRCUITS
G. SOP-214 PHYSICA�SECURITY PLAN FOR LOW IMPACT BCS
H. SOP-215 ELECTRONIC ACCESS CONTRQL FQR LOW IMPAGT BCS
I. FIXED CAMERA LOCATION MAP
J. SUBSTATION FENGE SPECIFICATION
Redding Electric Utility Security Plan
June 1, 2021
A. (:,C�,�L CF UTILITY S�CU'RITY I?LAN
Ensuring the safety of its facilities is a top priority for Redding Electric Utility (REU), and REU prioritizes
safety in all aspects of its design, operation, and maintenance practices.The overarching goal af
this Utility Securifiy Plan (Plan) is to describe REU's risk management approach toward distribUtion
system physical security, with appropriate consideration of resiliency, impact, and cost.
REU recognizes the importance of securing the safety and reliability of its electric system and,
therefore, REU voluntarily participated in the California Public Utilities Commission's (CPUC)
Physical Security proceeding and has undertaken this assessment. In the spirit of continued
voluntary cooperation, REU offers the follawing in response to CPUC Decision 19-01-Ol 8.
The REU Security Plan develapment scheduBe is provided beBow.
• July 10, 2020 - Initial Draft Mitigation Plan (optional for POUs)
• May 10, 2021 - Redding Police Department (third-party review)
• May 17, 2021 - Redding Fire Department (Validation of Plan)
• June 1, 2021 - Adoption of Plan by City Council
• July 10, 2021 -30 months fram effective date provide CPUC Safety and Enforcement
• Qivision with notice of final plan adoption (NLT 30 Days after adoption)
This Plan will be reviewed and updated at least every five years from initial adoption.A notification
of the program acceptance and notifications of future updates will be submitted ta the CPUC
within 30 days of adoption of the plan.
B. C�ESCR�P1'IQN C�F REDD�NU ELE�TRIC U1`ILITY
REU services 44,358 meters within 61 square miles of service territory. REU has 743 miles of 12kV
power lines, 72 miles of 1 15kV transmission lines, and 12 substations.
Redding Electric Utility Security Plan
June 1, 2021
Cb RE�ULTS C�F UTILITY SECtJRITY PLAN ASSESSMENT
REU owns and operates eleven (1 1) 115kV to 12kV distribution sUbstations and one (1) 13.8 kV to
1 15kV generation step up substation.
All but four substations have loads that are critical to the community normaliy connected to them.
Due to varying circumstances (planned or unplanned autages),all substations could have critical
loads connected and therefore this Plan will treat all af REU's substations as "covered" under the
ruling.
After assessment, no facilities required mitigation plans, however, optional security measures have
been identified for future incorporation as time and budget allows.
Redding Electric Utility Security Plan
June 1, 2021
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REU has been operating its electric system far almost 100 years. System protection for both public
and asset safefiy has been paramount.
In order to support a statewide improvement of how utilities address distribution level physical
security risks, the California Municipal Utilities Association (CMUA), which is the statewide trade
association for publicly owned utilities (POUs), coordinated with the state's investor owned utilities
(IOUs) to develop a comprehensive Straw Proposal (Joint IOU/POU Straw Proposal) far a process
to identify at-risk facilities and, if necessary, develop physical security mitigation plans. As a
member of CMUA, REU staff participated in the development of the Joint IOU/POU Straw Proposal
through a CMUA working group as well as through direct meetings with the IOUs. The Joint
POUlIOU Straw Proposal set out a process for the fallowing: (1) identifying if the utility has any high
priority distribution facilities; (2) evaluating the potential risks to those high priority distribution
facilities; (3) for the distribution facilities where the identified risks are not effectively mitigated
through existing resilience/security measures, developing a mitigation plan; (4) obtaining third
party reviews of the mitigatian plans; (5) adopting a document retention policy; (6) ensuring a
review process established by the POU governing board; and (7) implementing information
sharing protocols.
The Risk Assessment and Safety Analytics (RASA� unit of CPUC's Safety and Enforcement Division
filed a response to the Joint IOU/POU Straw Proposal that recommended various modifications
and clarifications, including a six-step process. Additionally, RASA recommended that the utility
mitigation plans include: (1) an assessment of supply chain vulnerabilities; (2) training programs for
law enforcement and utility staff to improve communication during physical security events; and
(3J an assessment of any nearby communication utility infrastructure that supports priority
distribution substations.
REU is following the process outlined in California Senate Bill (SB) 699 and issuing this report at this
time to reflect its existing commitment to safety and to protecting its customers' investment by
taking reasonable and cost-effective measures in an effort to safeguard key assets of its
distribution system.
This ruling is the nexus for the fixed-camera technology contemplated in the Technology Solutions
Program of the REU Wildfire Mitigation Plan (WMP) (revised December 1, 2020) in providing
physical security ta 66Covered Distribution Facilities". This ruling was in effect and in view while the
WMP was developed. REU (along with other publiely owned utilitiesj is listed in, and subject to the
ruling. The assessment partion includes determining "the potential for emergency responders to
identify and respond to an attack in a timely manner". The Automatic License Plate Reader
technology and fixed cameras are�niquely able to meet that need as part of this Physical Security
Mitigation Plan. The potential security solutions specifically stated in the ruling include (1) access
measures and (2) "Deterrent-Measures to discourage unauthorized entry or breach af the facility
(e.g., cameras, lights); and (3) Coordination - Measures to further callaborate with law
enforcement as appropriate."
Redding Electric Utility Security Plan
June 1, 2021
Article XI, Section 7 of the California Constitution provides certain POUs with the authority to own
and operate their own utility systems and self-regulate their operations. REU as such is a municipal
utility governed by the Redding City Council who serves as the Utility Cammission.
According to the ruling, the goal is "to establish system-wide ind�stry standards that are aimed at
addressing the potential risks and threats assaciated with a long-term outage at a distribution
facility an a statewide basis...", "and...not designed to expand Commission [California Public
Utility Commission] investigatory or penalty authority against the POUs."
REU is a department within the City of Redding. For security, crime prevention, and response, REU
is subordinate to the City of Redding Police Department (RPD).
Redding Electric Utility Security Plan
June 1, 2021
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A. PNYSICAL SECURITY F'RINCIPI..�$
The Joint IOUOPOU Straw Proposal sought to support the creation of a risk management approach
toward distribution system physical security,with appropriate considerations of resiliency, impact,
and cost. In order to accomplish this risk-based approach, the Joint IOU/POU Straw Proposal
identified several principles to guide the develapment of each individual utility's program. These
principles are the fallowing:
1. Distribution systems are not subject to the same physical security risks and associated
consequences, including threats of physical attack by terrorists, as the transmission system.
2. Distribution utilities will not be able to eliminate the risk of a physical attack occurring,
but certain actions can be taken to reduce the risk or consequences, or both, of a
significant attack.
3. A one-size-fits-aIB standard or rule will not work. Distribution utilities shouBd have the
flexibility to address physical security risks in a manner that works best for their systems and
unique si�uations, consistent with a risk management approach.
4. Protecting the distribUtion system should consider both physical security protection and
operational resiliency or redundancy.
5.The focus should not be on all Distribution Facilities, but only those that risk dictates would
require additional measures.
6. Planning and coordinatian with the appropriate fed�:ral and state regulatory and law
enforcement authorities will help prepare for attacks on the electrical distribution system
and thereby help reduce or mitigate the potential consequences of sUch attacks.
Additional principles that gUide REU include:
7. Incr�ase the level of security through situational awareness and technology as provided
by REU's Wildfire Mitigation Plan - T�chnology Solutions Program (WMP-TSP) and the
Emergency Operations Program (WMP-EOP).
8. Ensure the distribution system provides reliability through redundancy.
9. Provide opportunities ta better coordinate with Law Enforcement, specifically RPD.
10. Incorporate the security features described in this plan at new or modified substations.
1 1, Ensure industry best practices are considered and implemented as appropriate and
cost-effective.
Redding Electric Utility Security Plan
June 1, 2021
B. Uti[it� Security Plar� C���eloprner�� Prace�s
The major focus of this Plan is ta address the risks and threats of a long-term outage ta a distribution
facility. Clearly, a long-term autage at any distribution facility poses numerous safety issues.
This Plan describes the range of activities that REU is taking or considering to protect its distribution
assets, including its various programs, policies, and procedures. This Plan complies with the
requirements of CPUG section 364 for publicly owned electric Utilities to prepare a physical secUrity
plan by July 10,2Q21,and every five years thereafter.The Plan will be iterative, pramote continuous
improvement, and represent best efforts to implement industry best practices in a prudent and
reasonable manner.
REU utilized a multi-step process to develop this Utility Security Plan that is consistent with fhe Joint
IOU/POU Straw Proposal and D.19-01-018. The relevant six steps of that process are the following:
STEP 1 : ASSESSMENT/PLAN DEVELOPMENT
REIJ staff prepared a Draft Utility Security Plan through the process set forth in Steps 1 A, 1 B, and
1 C. RPD and REU coordinated on the assessment of the substation security plan.
STEP lA: IDENTIFY COVERED DISTRIBUTION FACILITIES
REU evaluated all distribution-level facilities in its service territory that are subject to its control to
determine if any facility m2ets D.19-01-018's definition of a "Covered Distribution Facility" using the
seven factors identified in the Joint IOU/POU Straw Proposal.
REU owns and operates eleven (1 1) 115kV to 12kV distribution substatians and ane (1) 13.8 kV to
1 15kV generation step up substation.
T le 1 I entific tion of " overe F cilities"
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Redding Electric Utility Security Plan
June 1, 2021
All but four substations have loads that are critical to the community normally connected to them.
Due to varying circumstances (planned or unplanned outages),all substations could have critical
loads connected and therefore this Plan will treat all of oUr substations as "covered" under the
ruling.
STEP 1 B: PERFORM RISK ASSESSMENT
For every individual Covered Distrib�tion Facility identified pursuant to Step 1 A, REU will perform an
evaluation of the potential risks associated with a successful physical attack on that Covered
Distribution Facility, and whether existing grid resiliency, back-up generation, and/or physical
security measures appropriately mitigate identified risks.
In addition to the physical security measures, our distribution system has flexibility and redundancy
built into it through field switching. We are able to feed critical loads from different transformers
and even different sUbstations. Appendix F has the backup circuits listed for the critical loads
identified. Redding's system currently has excess substation capacity even during our highest
peak periods. Que to this capacity, we have been able to take one or more entire substations
offline in order to facilitate major system upgrades. That same approach coUld be used in the
event of an unplanned issue.
Furthermore, the Redding Power Plant provides 183MW of clean natural gas generation within the
service territory, enough to power the entire city for most of the year, similar ta a 60-square mile
micro-grid.
Redding also has a new and unused substation transformer at the College View Substation that
could be relocated and installed in the event of a catastrophic failure. Other inventory includes
transformer bushings, CCVTs, protective relays, and other critical components.
STEP 1 C: DEVELOP MITIGATION PLAN
While ali "covered" facilities have adequate physieal security and resilience, there are additional
technologies and cooperation underway in order to increase situational awareness by both utility
operations and law enforcement. These enhancements have been defined and budgeted
through REU's WMP-TSP and WMP-EOP. Many of these measures will be completed by the July
2021 deadline.
Within the Ruling, there are four strategies where this Plan, through the implementation ofi the
WMP-TSP, and WMP-EOP, and planned capital improvements, will enhance our existing physical
security measures:
1. Respanse Time - Measures ta improve the potential for emergency responders to identify
and respond to an attack in a timely manner;
2. Deterrent - Measures to discourage unauthorized entry or breach of the facility (e.g.,
cameras, lights);
3. Access-fences, gates, and barriers or other security devices; and
4. Coordination-Measures ta collaborate with law enfarcement.
Redding Electric Utility Security Plan
June 1, 2021
The WMP - TSP includes provisions for fixed cameras including AUtomatic License Plate Readers
(A�PR� and high definition cameras. Each type of camera provided meets different strategies.The
ALPR technology can decrease response time significantly. With the appropriate notifications,
RPD could be aware of a potential threat already identified by other agencies and when or if that
threat comes near REU facilities, they would receive notification.
The fixed cameras provide a deterrent around REU facilities as well as general visual indication of
threats including wildfires.
The WMP-EOP includes the implementation of a Department Operations Center (DOC) where all
of the information from the cameras, our utility operations SCADA system, GIS systems, and other
fire awareness technology are gathered.The DOC becomes a physical place to coordinate with
first responders and the technology of the DOC provides virtual coordination to utility staff and firsfi
responders.
All of these strategies and technologies combine to provide enhanced situational awareness.This
alang with improved planning, coordination, and training with RPD provides a very high level of
security for REU's distribution assets.
The following initiatives will be implemented as time and budget allows to improve the resilience
of all REU substations:
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STEP 2: INDEPENDENT REVIEW
For every Utility Security Plan cycle, REU will document the results of the identification process, risk
assessment, and Mitigation Plan development performed pursuant to Steps 1 A, 1 B, and 1 C. This
documentation in combination with narrative description in Section IX below constitutes REU's
Draft Utility Security Plan. Each Draft Utility Security Plan is submitted to a Qualified Third Party for
Independent Review.The Qualified Third-Party Reviewerwill then issue an evaluation that identifies
any potential deficiencies in the Draft Utility Security Plan as well as recommendations for
improvements. REU will then modify its plan to address any identified deficiencies or
recommendations, or will document the reasons why any recommendations were not adopted.
REU's Utility Security Plan will consist of the Draft Utility Security Plan, the non-confidential
conclusions of the Qualified Third-Party Reviewer, and REU's responses to the Qualified Third-Party
Review.
RPD will conduct the independent review. REU coordinates with RPD and is subordinate for
emergency and pUblic safety issues. REU will work closely with RPD for situational awareness and
Redding Electric Utility Security Plan
June 1, 2021
other publie safety issues related to this Plan. RPD will review this Plan and provide comments for
consideration by REU. If any suggested changes are not incorporated, justification will be
documented and included in Appendix B.
STEP 3: VALIDATION
Under guidance of the California Public Utility Commission, validation of REU's Plan was
conducted by the City of Redding Deputy Fire Chief on May 17, 2021 prior to approval from the
City Council. A validation memo is attached as an Appendix to the Plan.
STEP 4: ADOPTION
REU's Utility Security Plan will be presented to and adopted by the Redding City Council at a public
meeting.
STEP 5: MAINTENANCE
REU will refine and update the Utility Security Plan as appropriate and as necessary to preserve
plan integrity.
STEP 6: REPEAT PROCESS
REU will repeat this six-step process at least onee every five years.
Redding Electric Utility Security Plan
June 1, 2021
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As described in Section Iil, Step 1 A, the Utility Security Plan identification process involves assessing
all distribution-level facilities that are subject to the control of REU to determine which facilities are
"Covered Distributian Facilities" and require a risk assessment. This Section describes the factors
that REU used to evaluate its distribution facilities and the results of its evaluation.
A. IC��NTIFICATIC7N F'ACTC�RS
The Joint IOU/POU Straw Proposal defines seven screening factors to determine if a facility is a
"Covered Distribution Facility." Some factors require additional definitions and/or clarifications in
order to be applied to REU's facilities. The following Table provides the Joint IOU/POU Straw
Proposal's Factars as madified/clarified by REU.
Factor Joint 1; UjP tl S�raw Prt� z��t�l �scri tion Additic�nal'Clarifica#'rc�n'
Distribution Facility necessary for crank path, No additional clarification.
black start or capability essential to the
restoration of regional electricity service
that are nat subject to the California
1 Independent System Operator's (CAISO)
operational eontrol and/or subject to North
American Electric Reliability Corporation
(NERC) Reliability Standard CIP-014-2 or its
successars
Distribution Facility that is the primary source No additional elarification.
of electrical service to a military installation
essential to national security and/or
2 emergency response services (may include
certain airfields, command centers,
weapons stations, emergency supply
depots
Distribution Facility that serves installations An installatian pravides "regional drinking
necessary for the provision of regional water supplies and wastewater services" if
3 drinking water supplies and wastewater it is the primary source of drinking water
services (may incBude certain aqueducts, supply or wastewater services for over
well fields, groundwater pumps, and 40,000 eustomer accounts for an area
treatment plants) with a population af over 100,000.
Distribution Facility that serves a regional REU defines "regional public safety
pubiic safety establishment (may include establishment" as any of the following: (1)
Gounty Emergency Operations Centers; Headquarters of a major poliee or fire
caunty sheriff's department and major city department serving 1,5 million population
poBice department headquarters; major with at least 1,000 sworn officers; (2)
4 state and county fire service headquarters; County Sheriff's Department
co�nty jails and state and federal prisons; Headquarters; (3) Co�nty Emergency
and 911 dispatch centers) Operations Center; (4) County/State Fire
headquarters; (5) a California State Prison;
(5) a United States Penitentiary; or (6) a
Federal Correctional Institute.
Redding Electric Utility Security Plan
June 1, 2021
Distribution Facility that serves a major In additian to the facilities listed in the
transportation facility (may include Joint IOU/POU Straw Proposal, REU defines
Internatianal Airport, Mega Seaport, other a "major transportation facility" as any
5 air traffic control center, and international transportation facility that has (1) an
border crossing) average of 600 or more flights per day; or
(2) over 50,000 passengers arriving or
de artin er da .
Distributian Facility that serves as a Level 1 No additional clarification.
6 Trauma Center as designated by the Office
of Statewide Health Planning and
Develo ment
Distribution Facility that serves over 60,000 No additional clarification.
7 meters
�. �DENT]F�cA1"CC}N ANA�YsIs
In performing this identification analysis, REU assessed all distrib�tion level faeilities that are subject
to its exclusive control, or if the facility is jointly owned, facilities where the joint ownership
agreement identifies REU as the entity responsible for operation and maintenance. The specific
types of facilities include substations and the power plant.
� I
,
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Redding Electric Utility Security Plan
June 1, 2021
A. METF-��C�C?LC?GY
Pursuant to the process identified in the Joint IQU/POU Straw Proposal and D.19-01-018, REU
assessed the potential risks associated with a successful physical attack on each of the Covered
Distribution Facilities identified in Section IV. For the purpose of this analysis, a physical attack is
limited to the following: (1) theft; (2) vandalism; and (3) discharge of a firearm. A "successfUl
physical attack" is limited to circumstances where a theft, vandalism, and/or the discharge of a
firearm has directly led to the failure of any elements of the Covered Distribution Facility that are
necessary to provide �ninterr�pted service to the specific load identified in Section IV.
In order to perform this risk analysis, REU evaluated the relative risk that (1) a physical attack an a
Covered Distrib�tion Facility will be successful eonsidering the protective meas�res in place; or (2)
the impacts of a successful attack will be mitigated due to resiliency and other measures in place.
B, MITIGATI�?N M�A�URE�
D.19-01-018 identifies the specific mitigation measures that a utility should consider when
perfarming this risk analysis. The following tabl2 lists these mitigation measures and provides REU's
additional clarifications that are necessary to apply these measures to the REU's territory.
�asure' b.19��1-�18 �es�ri ti�n Add�ti�na;!�iarificati�n
The existing system resiliency and/ar No additional clarification.
redundancy solutions (e.g., switching the
1 load to another substation or circUit
capable of serving the load, temporary
circuit ties, mobile generation and/or
storage solutions .
The avaiBability of spare assets to restore a No additional clarifieatian.
� particular load.
The existing physical security protections to No additional clarification.
3 reasonably address the risk.
The patential far emergency responders to Each facility is evaluated based on
identify and respond to an attack in a the likelihood that a law enforcement
timely manner. officer would generally be able to
arrive at the Covered Distribution
4 Facility within 15 minutes of a report
from the pUblic of a break-in or
attack, or af REU notifying the law
enforcement agency of triggering of
an alarm at the facility.
Location and physical surroundings, REU evaluated this element based on
5 including proximity to gas pipelines and the proximity of the Covered
geographical challenges, and impacts of Distribution Facility to populated areas
weather. and the extent to which the interior of
Redding Electric Utility Security Plan
June 1, 2021
the facility is shielded from view and
access due to walls, vegetatian, or
other physical obstruetions.
History of criminal activity at the Distribution REU evaluated the property crime
Facility and in the area. rates in the immediate vicinity of the
Covered Distribution Facility and
6 compared those crimes rates to
property crime rates for the caunty
and the state to determine if the area
is subject to a higher than average
incidence of ro ert related crimes.
The availability of other sources of energy No additional clarification.
7 to serve the load (e.g., customer owned
back-up eneration or stora e solutions .
The availability of alternative ways to meet No additional clarification.
the health, safety, or security.
Requirements served by the load (e.g., No additional clarification.
9 back up command e2nter or water
stora e facility�.
' C. RISK A�S�SS1v1ENT
Based on the process described in the Joint IOU/POU Straw Proposal and the directian provided
in D.19-01-018, REU has determined that of the eight Covered Distribution Facilities identified in
Section IV, the existing programs and measures effectively mitigate the risks of a physical attack
for all of those Covered Distribution Facilities.
�
Redding Electric Utility Security Plan
June 1, 2021
Redding Electric Utility Security Plan
June 1, 2021
� l ( , ���
� �,:,. � �
I
����� ' � � � � � � � � � '
� ' � � � � � � � �
- ', � � � � � � � � �
�� � � � � � � � �
As identified above, all of the Covered Distribution Facilities have existing measures sufficient to
effectively mitigate the identified risks of a physical attack.
Redding Electric Utility Security Plan
June 1, 2021
` , A
Pursuant to the process identified in the Jaint IOU/POU Straw Propasal and D.19-01-018, REU has
determined that for the Covered Distribution Facilities s�bject to REU's control, the exisfiing
mitigation measures sufficiently reduce the risk of a physical security attack.
r r • • r
A. l�Et�UlRE1ulENTS FC?R C�UALIFI�L� TH1RC?-PAI�TY R�VI�W
D.19-Q1-018 specifies the following criteria for a Qualified Third-Party Reviewer:
Independence: A Qualified Third-Party Reviewer cannot be a division of the POU. A
gavernmental entity can select as the third-party reviewer another governmental entity
within the same political subdivision, so lang as the entity has the appropriate expertise,
and is not a division of the POU that operates as a functional unit, i.e., a municipality could
use its police department as its third-party reviewer if it has the appropriate expertise.
Adecivate Qualifications: A Qualified Third Party Reviewer must be an entity or
organizafiion with electric industry physical security experience and whose review staff has
appropriate physical security expertise, which means that it meets at least one of the
fallowing: (1) an entity or organization with at least one member who holds either an ASIS
International Certified Pratection Professional (CPPJ or Physical Security Professional (PSP�
certification; (2) an entity or organization with demonstrated law enforcement,
government, or military physical security expertise; or (3) an entity or organization
appraved to do physical security assessments by the CPUC, Electric Reliability
Organization, or similar electrical industry regulatory body.
�. IL:��NTI�I�ATIC�N �7F THI12[�-Pfi��27�1' I2E�ICEWEf2
REU has selected RPD as its Third-Party Reviewer.
As a municipality, under D.19.01.018, RPD has the appropriate expertise to act as the third-party
reviewer.
�� P(J�LI� RESlJLTS QF TNIR[�-F'/�RTY E�IALIJATI(�N
The Redding Police Department campleted their review of REU's Utility Security Plan and visited
numerous substation sites. The Independent Review is attached as Appendix B.
' C?. REU i2ESf'C?I�IS�
REU met with the Independent Evaluator and conc�rs with the recommendations listed in
Appendix B.
Redding Electric Utility Security Plan
June 1, 2021
. , .
A, SEL�CTIC�N C7F C�UAL1Fl�� AUTHC�#21TY
Under guidance of the California Public Utility Commission, validation of REU's Plan was
conducted by the City of Redding Deputy Fire Chief prior to City Council approval and is
attached as Appendix C.
B. RESULTS C�F C�UALIFIEC7 AUTHC7RITY R��/IEW '
REU concurs with both the third-party review and validation report cond�cted by security experts
from the Redding Police and Redding Fire Departments.
Redding Electric Utility Security Plan
June 1, 2021
a ♦ ,
�. �u)��1 ����k,7'����� 1- R��.71�.�� '�.
In 2007 REU began implementing the substation modernization program that was completed in
2019. The program upgraded all substation controls and protection systems with standardized
components.This approach reduces the quantity of spare parts needed as the same equipment
is used in all subsfiations for controls and protection.
REU has both a central warehoUse as well as spare part inventories at each substation. There are
spare parts for all substation components, including a 28MVA 1 15KV/12KV transformer which is the
highest cost and longest lead time item.
REU participates in the Electricity Information Sharing and Analysis Center (E-ISAC) for physical
security notifications as well as coordination through various joint pawer authorities. REU is also a
member of the California Utilities Emergency Association (CUEA) for fast respanse mutual aid.
�. WC�RKFC?RC� TRAJNIN� ANC7 RET�NTI�.7N F'RC��RAM
REU conducts ar�nual salary and campensation studies for recruitment and retention af highly
q�alified staff. By maintaining well trained and qualified employees, REU is able to respond quickly
to any equipment needs or repairs within the City of Redding substations. Inventory of equipment
far substatians is monitored and kept on hand to ensure a timely response for any issues that may
arise.Since training for technical staff is a high priarity, REU has a substation controls training facility
for testing new products and improving competency for existing equipment used in the
substations.
C. PREVENTATI�E MAINTENfi.Nt,;� PLAN
Redding Electric Utility Security Plan
June 1, 2021
C�. F'NYSI�AL SEC;URITY E�ENT 1"RAfNING
REU's DOC will incorporate substation security during annual emergency aperations training with
all departments in the City of Redding, including the Redding Police and Fire Departments.
�. CI�MMUNI�ATIC�N IN�I2ASTRUCTUR� RISK A55ESSt�tENT
The citywide radio eqUipment on Southfork Mountain, west of the City of Redding, is subject to
both wildfire and snow storms which impacts emergency radio communication within the City af
Redding. REII is replacing the current citywide radio system for p�blic safety and utility
infrastructure. The new radio sites will be placed within the city limits, reducing the impacts due to
poor weather canditions and public safety power shutofifs (PSPS).
F, FACILITY [��51C:�N FEATURES
As part of the risk mitigation to the substations, REU is studying various security measurements for
future installation.
REVISION NISTORY
Version ' Re�risi�n Surnmary of Changes
u �r ate
1.0 b/1/21 Initial
Redding Electric Utility Security Plan
June 1, 2021
This Page Tntentionally Left Blanlc
CQM/CR6/avs ate of Issuance 1/2 2019
Decision 19-01-018 January 10, 2Q19
T LI TILITI I 1 F T T T LI I
Order Instituting Rulemaking
Regarding Policies, Procedures and
Rules for Regulation af Physical
Security for the Electrzc Supply
Facilities of Electrical Corporations
Consistent with Public Utilities Code
Section 364 and to Establish Standards Rulemaking 15-Q6-OQ9
for Disaster and Emergency
Preparedness Plans for Electrical
Corporations and Regulated Water
Companies Pursuant to Public Utilities
Code Section 768,6.
PHASE I DEClSION ON QRDER INSTITUTING RULEMAKING
REGARDING THE PHYSIGAL SECURITY OF
E�ECTRICAL CQRPORATIQNS
26Q33S905 - 1 -
R.15-Q6-009 COM/CR6/avs
TABLE OF CONTENTS
Title age
PHASE I DECISION ON ORDER INSTITUTING RULEMAKING
REGARDING THE P�IYSICAL SECURITY OF ELECTRICAL
CORPORATIONS ....................................................................................................2
Summary..................................................................................................................2
1. Factual Background...........................................................................................3
1.1. Procedural Background............................................................................5
2. Electric Physical Security Prior to Metcalf .....................................................9
3. JurisdictionalIssue...........................................................................................10
3.1. Position of CMUA, LADWP, NRECA and SMUD............................11
3.3, Safety Palicy Concerns Support Commission
Jurisdiction by POUs in Phase I............................................................19
3.4. Phase II Jurzsdzction ................................................................................22
4. The Joint Utility Proposal ...............................................................................23
4.1. Identification............................................................................................24
4.2. Assessment...............................................................................................26
4.3. Mitigation Plan ........................................................................................27
4.4. Verification...............................................................................................28
4.5. Records......................................................................................................29
4.6. Timelines and Prequency.......................................................................30
4.7. Cost............................................................................................................30
5. SED RASA Staff Evaluatxon of Joint Utilzty Proposal,
Security Plan Element and SED RASA Recommendations ......................31
6. Guiding Principles af California Electric Physical Security .....................32
6.1. Six-Step Procedure to Address Utilities' Distribution Assets ..........32
6.2. Additional Requirements for Mitigation Plans ..................................34
6.2.1. Additional Optional Requirements for Mitigation Plans...................35
6.3. Third-Party Verification.........................................................................36
6.4. Third-Party Expert Qualifications ........................................................37
6.5. Access to Information.............................................................................38
6.6. Timeline for Implementation.................................................................41
6.7. Reporting..................................................................................................41
6.8. Cost Recovery ..........................................................................................42
7. Commission Position on Joint Utility Proposal and SED RASA
Recommendations...........................................................................................43
8. Safety Considerations......................................................................................44
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TABLE OF CONTENTS
Con`t.
Tifile Page
9. Conclusion ........................................................................................................44
10. Comment Period..............................................................................................44
11. Assignment of Proceeding.............................................................................45
Findingsof Fact ......................................................................................................45
Conclusians of Law................................................................................................49
ORDER .......................................................................................5Q
..............................
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R.15-Q6-009 COM/CR6/avs
PHASE I DECISION taN ORDER INSTITUTING RULEMAKING
REGARDlNG THE PHYSICAL SECURITY
C)F E�ECTRICAL CORPORATIONS
Summary
This decision requires electric utilities to identify electric distribution assets
that may merit special protection and measures to lessen identified risks and
threats. In order to address the risk of long-term autage to a dzstribution facility,
each Operator will develop and implement a Mitigation Plan. The Mitigation
Plans wi11 £ollow a s�x-step procedure for carrying out these new physical
security plan requirements. The six-step plan is modeled on the security plan
requirements set forth by the North America Electric Reliability Corporation
(NERC) Critical Infrastructure Protocol (CIP)-014.
This decisian requires the Investor Owned Utilities (IOUs) to prepare and
submit to the Commission a preliminary assessment of priority facilities for their
distribution assets and control centers (`"covered assets") within 18 months of
this decision. An unaffiliated, third-party review of the plans should be
completed within 27 months of this decision. Within 30 months of this decision,
the IOUs will be required to submit their Final Security Plan Report. Within
3Q months, each of the Publicly C?wned Utilities (POUs) will be required to
provide the Commission with notice that an independently-reviewed plan has
been adopted.
Sections 8Q01-8057 of the Public Utilities Code compel the POUs to also
adhere to this decision as it relates to physical security and Phase I af this
proceeding.
Any new rules for emergency and disaster preparedness plans
promulgated within Phase II of this proceeding will not apply to the POUs.
However, the PQUs are strongly encouraged to participate in Phase II. This
R.15-Q6-009 COM/CR6/avs
proceeding will remain open at the conclusion of Phase I to address Phase II
issues.
1. Factual Background
In Apri12013, a rifle attack at PG&E's Metcalf Transmission Substation
south of San Jose resulted in approximately $15.4 million in damages. Although
PG&E initiated variaus changes to its security protocol, in late August 2014,
burglars entered the Metcalf facility and removed $38,651 of tools and
equipment,1 Changes were made to Pub. Util. Code � 364(a) as a direct result of
the Metcalf incident, addressing the vulnerability of electrical supply facilities to
physical security threats. Phase I of this proceeding was initiated by Senate Bill
(SB) 699 (Stats. 2014, Ch. 550, Sec. 2),
The Federal government swiftly responded to the Metcalf attack, resulting
in new additional provisions to the decade-old Critical Infrastructure Protocols
(CIP). These were developed in a rulemaking conducted by the Federal Energy
Regulatory Commission (FERC). FERC directed the North American Electric
Reliability Corporation (NERC) to establish various criteria for determining
which assets would be subject to the new CIP rules. The CIP rules cover both
physical- and cyber-security rules.
The new CIP rules and requirements (CIP-014) require electric utilities to
employ physical security plans as a way to address vulnerabilities. Among other
things, CIP-014 applies to any asset deemed not redundant and for which failure
of these assets could result in cascading power failures. These rules established a
risk-based protocol that identifies critical transmission assets and control centers.
1 PG&E Metcalf Raot Cause Analysis Summary Report. November 21,2014, at 2.
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CIP-014 authorized FERC to establish a uniform, mandatory physical security
standard for the nation`s transmission assets.
On June 11, 2Q15, the Commission issued an Order Instituting Rulemaking
(OIR) to establish policies, procedures, and rules for the regulatian of physical
security risks to the electric supply facilities of electrical corporations consistent
with Public Utilities (Pub. Util.) Code � 364 (Phase I} and to establish standards
for disaster and emergency preparedness plans for electrical corporations and
regulated water companies conszstent with Pub. Util. Code � 768.6 (Phase II).2
SB 699 amended Pub. Util. Code � 364 and requires the Commission to
develop rules for addressing physical security risks to the distribution systems of
electrical corporations. Section 364 was amended by SB 699 to read:3
The commission shall ... consider adopting rules to address
the physical security risks to the distribution systems of
electrical corporations. The standards or rules, which shall be
prescriptive or performance based, or both, and may be based
on risk management, as appropriate, for each substantial type
of distribution equipment or facility, shall provide for high-
quality, safe, and reliable service.
Section 364(b) continues in relevant part that:
In setting its standards or rules, the commission shall
consider: cost, local geography and weather, app�icable
2 This decision addresses only Phase I issues. A decision addressing Phase II issues will be
issued once Phase II of this proceeding has concluded.
3 Section 364 was subsequently an�ended by SB 697, effective January 1,2016. The subsequent
changes to �364 after the passage of SB 699 can be found at the following 1ink:
http://leginfo legislature.ca.gov/faces/billCompareClient.xhtml?bill_id=201520160SB697.
Although it might appear that the annual reporting requirement has been deleted from�364, as
a result of SB 697,this language has simply been relocated fio �590.
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R.15-Q6-009 COM/CR6/avs
codes, potential physical security risks, national electric
industry practices, sound engineering judgment, and
experience. The commission sha11 also adopt standards for
operation, reliability, and safety during periods of emergency
and disaster. The commission shall require each electrical
corporation to report annually on its compliance with the
standards or rules. Except as provided in subdivision (d), that
report shall be made available to the public.
Phase II of thxs proceeding was instituted as a result of Pub. Util. Code
§ 768.6 being added to the Pub. UtiL Code by Assembly Bill (AB) 1650. It
requires the Commission to:
Establzsh standards for disaster and emergency preparedness
plans within an existing proceeding, including, but not
limited to, use of weather reports ta preposition manpower
and equipment before anticipated severe weather, methods of
improving communications between governmental agencies
and the public, and methods of working to control ancl
mitigate an emergency or disaster and its aftereffects.
This language bears similarities to the pre-amendment version of � 364(b), which
states:
In setting xts standards, the commission shall consider: cost,
local geography and weather, applicable codes, national
electric industry practices, sound engineering judgment, and
experience. The commission sha11 also adopt standards for
operation, reliability, and safety during periods of emergency
and disaster.
Phase II of this proceeding is ongoing.
1.1. Procedural Background
An initial prehearing conference (PHC) was held on Qctober 29, 2015. A
supplemental PHC was conducted on Pebruary 2, 2017 and a Scoping Memo and
Ruling was issued on March 10, 2017.
The scoping memo set forth the following issues to be addressed in this
proceeding:
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R.15-Q6-009 COM/CR6/avs
1. What is currently in place in terms of physical security
regulations at the state and federal level?
2. What are the key potential physical security risks to
electrical distribution facilities?
3. What new rules, standards, or General Orders or
modifications to existing policies should the Commission
conszder to help mitigate physical security risks to
electrical distribution facilities?
4. Should the Commission go beyond the physical security
regulations presented in the NERC CIP-014-2 physical
security regulations?
5. Should any new rules, standards, or General Orders or
modifications to existing policies apply to all electrical
supply facilities within the jurisdiction of the Commission,
including publicly owned electrical utilities and rural
electric cooperatives?
6. What regulations or standards should be established for
small and multi-jurisdictional electric corporations?
7. What has changed since Metcal£ and what still needs to be
accomplished in terms of physical security?
8. Are there other factors not listed in Section 364(b) of the
Pub. Util. Code that the Commission should consider
when adopting any new rules, standards, or General
Orders or modifications to existing pol�c�es during this
rulemaking that will help to minimize attacks and the
extent of damages?
9. What new rules or standards or modifications to exxstzng
policies should the Commission consider to allow for
adequate disclosure of information to the public without
disclosing sensitive znfarmation that could pose a physical
security risk or threat if disclosed?
10. What is the role of cost and risk management in relation to
the mitigation of any potential physical security risks to
electrical supply facilities?
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R.15-Q6-009 COM/CR6/avs
11. �hould any new rules, standards, or General Orders or
modifications to existing palicies the Commission
considers be prescriptive or performance based, or both?
12. What new rules, standards, or General Orders or
modifications to existzng policies should the Commission
consider to ensure continued operation, reliability and
safety during periods af emergencies and disasters as it
relates to the physical security of electrical facilities?
13. How should this rulemaking proceed in order to ensure
consistency w�th the NERC, Federal Energy Regulatory
Commissions (FERC), the California lndependent System
Operator (CAISO), the Department of Homeland Security
(DHS), the Federal Bureau of Investigat�ons (FBI) and
other regulatory agency regulations?
14. What ongoing processes should be instituted to ensure
confidentiality of physical security information while
providing adequate access to necessary information by the
�(JI7iT111SS10114?
On July 12, 2Q17, the assigned Administrative Law Judge (ALJ) issued a
ruling requesting that parties file a Straw Praposal for Physical Security
Regulations (Joint Utility Proposal). The Joint Utility Proposal was fi�ed on
4 Despite the sensitive nature of the documents involved,we remind fihe ufiilities that even
without the compulsion of a subpoena, the Commission may under Pub. Util. Code
Sections 313, 314,314.5,315, 582, 584,591, 701, 702, 1794 and 1795, compel information from a
public utility, and that Commission staff has the general investigatory authority of the
Commission. Specifically,we remind the utilities that pursuant to these provisions the
Commission may direct the utilities to provide the requested information in a place and form of
the Commission's choosing. Any confidential or sensitive information should be marked as
confidential pursuant to Section 583,which mandates the non-disclosure of such informatzon.
and in accordance with the process for declaring exemptions from public disclosure per General
Order 66 D adopted by D.17-09-023 in R.14-11-001, and revised by Assigned Commissioner's
Ruling of September 28, 2018.
_ �_
R.15-Q6-009 COM/CR6/avs
August 31, 2017.5 On September 14, 201�, the Office of Ratepayer Advocates
(ORA)h and the Electric Safety and Reliability Branch of the Safety and
Enforcement Division (SED Advocacy) filed comments on the Joint Utility
Proposal.
On January 3, 2018, the assigned ALJ issued a ruling allowing the parties
to file legal briefs concerning the Commissian's jurisdiction over POUs and rural
electric cooperatives. CMUA, LADWP, NRECA and SMUD filed a joint opening
brief on January 26, 2018, opposing any attempt by the Commission to assert
safety jurisdiction over the POUs and rural cooperatives. Also, on
January 26, 2018, SED Advocacy� and ORA filed briefs in support of the
Commission`s ability to assert jurisdiction over the POUs. Qn February 9, 2018,
CMUA, LADWP, NRECA and SMUD jointly filed a reply brief on the
jurisdictional issue. SED Advocacy also filed a reply brief at the same time. On
January 4, 2Q18, SED's Risk Assessment and Safety Advisory (RASA) unit8
5 The parties to the Joint Utility Proposal are: Bear Valley Electric Servrce, CalzfornXa Municipal
Utilities Associafiion (CMUA),Los Angeles Departmenfi af Water&Power (LADWP),Liberty
CalPeco,National Rural Electric Cooperative Association (NRECA),PacifiCorp, Pacific Gas &
Elecfiric Company (PG&E) Sacramenfio Municipal Utility Disfirict (SMUD),San Diego Gas &
Elecfiric Company (SDG&E) and Southern California Edison Company (SCE).
6 Senate Bill (SB) 854 (Stats. 2018,ch. 51) amended Pub. Utii. Code�ection 309.5(a) so that the
Office of Ratepayer Advocates is now named the Public Advocafie's Office of the Public Utilifiies
Commission. Because the pleadings in this case were primarily filed under the name Office of
Ratepayer Advocates,we will refer to this party as ORA in this decision.
� In this proceeding, SED Advocacy is represented by the Electric Safety and Reliability
Branch (ESRB}.
g SED RASA is not a party in this proceeding but provides advisory support to the ALJ and
Assigned Commissioner.
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completed its recommendations and analysis on the Joint Utility Proposal9
(RASA evaluatian). On January 16, 2018, the assigned ALJ issued a ruling that
made available the RASA evaluation as an attachment and that requested
comments and reply comments on the RASA evaluation. Comments were filed
on February 9, 2018 by S�E, SDG&E, ORA, SED, SMUD, LADWP, and NRECA.
Reply comments were filed on February 23, 2018 by the same parties. On March
2, 2018, SCE filed sur-reply comments.
2. Electric Physical Security Prior to Metcalf
Before the Metcalf incident, electric physical security in the United States
had been voluntary and primarily directed at manitoring physical security
incidents. In 2001, NERC issued guidelines prescribing new physical security
requirements for electric ut�lities, and the Institute for Electric and Electronic
Engineers (IEEE) published its own guidelines titled 1402-20Q0 IEEE Guide for
Electric Power Substation Physical and Electronic Security.10
In 2010, the National Infrastructure Advisory Council, in conjunction with
the U.S. Department of I-�omeland Security (DHS), issued A Framework for
Establishing Critical Infrastrueture Resilienee Goals�� whieh defined resilience as the
ability to reduce the magnitude and/or duration of disruptive events. The report
noted the potential for public agencies to enhance the res�lience of the electricity
9 Safety�Enforeement Division's Risk Assessment£�Safety Advisory (RASA) seetion evaluation of the
Joint Utilzty P�oposal and Recommendation.s for Consideration available at
http.//docs.cpuc.ca.gov J PublishedDocs/Efile/G000/M204/K457/204457381.PDF
10 l��s:���tarac�ard�,i�e�.c�r��`sta�clardl14Q2-�2QOQ.htrra�.
11 htt �: /�vw�v,c�h�. csv���bli�at�c��/7�za�-fr;�r����c��°1c-e�t�l��zshi��-rc��ils�i�c�-��als-�i��1�
ze c�rt.
_ 9 _
R.15-Q6-009 COM/CR6/avs
sector through policy, planning, standards and regulations. The report also
stressed the importance of improving access to information regarding threats.
Early in 2013, Presidential Policy Directive 2112 established Federal
agencies' roles regarding physical- and cyber-security threats. These policies
reemphasized the need for a collaborative approach to security and risk
assessment, with the U.S. Department of Energy (U.S. DOE) overseeing issues
related to the electric utility sector through the newly-formed Electric Subsector
Coordinating Council (ESCC).
3. Jurisdictional lssue
When this rulemaking was initiated, CMUA, LADWP, NRECA and SMUD
objected to any attempt to have either Phase I or II af this proceeding be
applicable to them. They assert that the Commission does not have jurisdiction
to assert any new regulations on them. SED and ORA argue that there is an
underlying safety concern which mandates that this rulemaking apply to them.
CMUA, LADWP, NRECA and SMUD active�y participated in Phase I of
this proceeding. The insight and knowledge that they brought to this proceeding
was valuable and the Commission acknowledges their engagement and
contributions. Working together has allowed us to develop an extremely
�mportant set of standards to help ensure the safety of all residents in California.
The Joint Parties agreed to fully participate in Phase I and address the
issue of jurisdiction in legal briefs near the conclusion o£ Phase L The
Commission recognizes the high level of cooperation among everyone involved
1z l�tt�a�: f�b�rr�aw�it�hc����.�rcl�7�es,�c�__v_/t�a�-�res��c�ffie� 2013��32 12��ar��ic���tial@�c�lic�-
�li���tiv�-critieal-�i�fra�tr�z�t�re���c��rzt�-�nc��-�-��i�.
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R.15-Q6-009 COM/CR6/avs
with Phase I and encourages continued cooperation by everyone in Phase II. We
will now address why new Phase I rules apply to the POUs.
3.1. Position of CMUA, LADWP,
The POUs contend that Commisszon jurisdiction over POUs' physical
security is not supported by (1) the statutory language, (2) legislative history,
(3) case law, or (4) policy.
(1) Statutory Language and Legislat�ve I�xstory
The POUs argue that Article XI, Section 7 of the California Constitution
provides certain POUs with the authority to own and operate their own utility
systems and self-regulate their operations, and that the statutory and legislatzve
history demonstrate that SB 699 was not intended to apply to the PC�Us. SB 699
amended � 364 to provicle that "[t}he Commission shall ,.. in a new proceeding
... consider adopting rules to address the physical security risks to the
distribution systems of electrical corporations."13
The POUs argue they are not "electrical corporatians" as traclitionally
defined in 3 218,14 and that nothing in � 364 provides the Commission with
authority ta adopt such rules for the POUs.15 Moreover, they argue that POUs
do not fall within the meaning of "electrical corporations" referenced in � 364(a).
In support of this argument, the POUs quote extensively from SB 6991egislative
reports that appear to exclusively discuss IOUs or expressly state that POUs "are
13 Id. At 8.
14 Qpening Brief of CMUA, LADWP, NRECA and SMUD at 1Q.
15 Id. At 13.
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self-governing by a local government."1h They state that because the POUs are
not electrical corporations and the legislature did not explicitly refer to POUs in
� 364(a), it clearly intended to have the requirements of this provision apply
solely to the IOUs.
The POUs also state that nowhere in �� 8001-8057 did the Legislature
provide mechanisms for the Commission to enforce its adopted regulations
against a POU.17 Additionally, they state that � 2107 of the Pub. Util. Code,
which grants the Commission authority to perform investigations and levy fines
against the IOUs, does not apply to the POUs, and the Commission therefore
lacks the authority to levy fines or penalties against them.
(2) Case Law
In addition to statutory language and legislative history, the POUs rely on
County of Inyo v. Pub. Util. Comm`nl� for the proposition that the Commission
has no jurisdiction over them without express statutory authorization.
(3) Publie Policy Considerations
The POUs also argue that exempting POUs from the rulemaking would
not pose a public safety threat because POUs are beholden to thezr local boards
and oversight bodies, which are typically directly-elected officials put in office by
local voters. Because POU customers, the POUs explain, ultimately have the
ability to vote in or out POU board members, the POUs are held accountable and
function under close scrutiny of their local communities.
16 LADWP Opening Comments,July 22, 2015 at 3-5.
17 Joint Parties Opening Brief at 26-27.
18 County of Inyo v. Pub. Util. Comm'n,26 Cal. 3d 154 {1980) (Tobriner,J.).
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In 1996, the Legislature adopted � 364. Section 364(a) required the
Commission to "adopt inspection, maintenance, repair, and replacement
standards." These maintenance and inspection standards were promulgated and
applied to IOUs in D.9�-03-070. The standards were later applied to POUs in
D.98-03-036. CMUA asked for rehearing on the issue of jurisdiction over POUs,
which the Commission denied in D.98-10-059. CMUA then filed a petition to
modify D.98-03-036 and vacate D.98-1Q-059. This second petition was denied in
D.99-12-052.
Meanwhzle, � 364(b) required the Commission to "adopt standards for
operation, reliability, and safety during periods of emergency and disaster."
These emergency response standards were proposed in D.98-03-Q36 and applied
to ICJU� in D.98-07-097. However, D.98-07-097 clarified that the emergency
response standards did not apply to POUs.
D.98-03-036 and D.98-10-059 attempt to explaxn why the Commzssion has
jurisdiction over POUs with respect to � 364(a) inspection and maintenance
standards but not with respect to � 364(b) emergency response standards.
Specifically, D.98-03-036 asserts that under �� 8001-8057, the "Commission has
historically had authority over the public safety aspects of publicly-owned
utilities. . . 'for the purpose of safety to employees and the general public."'19 The
Commission further noted that it not only has the authority to regulate public
safety aspects of the publicly-owned utilities' operations, but that it has a duty to
do so under PU Code � 8037 and � 8056, which expressly required the
Commission to enforce such rules against POUs.20 The Commission`s
19 D.98-03-036 at 13.
20 D.98-03-036 at 8.
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jurisdiction over maintenance and construction was affirmed by the California
Supreme Court in Polk v. City of Los Angeles.21 The Legislature did not alter the
Commission's jurisdiction when it enacted � 364(a); the Commission therefore
rightly concluded that it could apply the maintenance and construction
standards to POUs.2z
CMUA argued that �� 8001-805� did not confer jurisdiction on the
Commission to regulate the public safety aspects af POUs, and characterized
Polk as merely holding that Commission safety rules established a POU's duty of
care in a negligence action. D.98-10-059 rejected CMUA's arguments.
More recently, the Commission summarized its jurzsdiction over POUs in
R.08-11-005: "Under Pub. Utxl. Code �� 8002, $037, and 8056, the Commiss�on's
jurzsdiction extended to publicly-owned 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."23
3.2. Legal Precedent
We now turn to the case law beyond these prior Commission precedents.
Both the POUs and SED Advocacy rely on County of Inyo24 to support contrary
positions. In County of Inyo, Inyo County initiated a complaint proceeding
against LADWP over water rates charged to the County and its residents.25 Inyo
2� Polk v. City of Los Angeles,26 Cal. 3d 519 (1945).
22 The jurisdictional analysis in D.98-03-036 was written confusingly. In D.98-07-097, the
Commission clarified that the emergency response standards did not apply to POUs but did not
explain further.
2� D.09-08-029 at 8.
24 County of Inyo v. Pub. Uti1. Comm`n,26 Cal. 3d 154 (1980) (Tobriner,J.).
25 Id. at 156.
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County argued there was a practical need for Commissian regulation because
Inyo residents could not vote in Los Angeles elections and thus had no political
remedy for unreasonable water rates charged by LADWP.2h The Commission,
however, dismissed the complaint for want of jurisdiction over POUs, as the
Legislature had not included POUs "within the classes of regulated public
utilities in divisions 1 and 2 of the Public Utilities Code."
Although the California Supreme Court determined that Commission
jurisdiction over POUs was a canstitutional possibility, as legislation conferring
PUC jurisdiction "would fall clearly within the scope of present article XII,
section 5 [of the California Constitution]," it also found that the Legislature had
never enacted such a statute to confer jurisdiction.27 Therefore, despite the
equities favoring Inyo County and its residents, the Court was obliged to affirm
the Commission's dismissal.
In this proceeding, the POUs argue that "the plazn language of Section 364
and SP 699's legislative history both confirm that POUs are outside the scope of
this OIR" because there is no statute granting jurisdiction.28
In D.98-1Q-059, the Commission cited to County of Inyo for the proposition
that "Article XII, section 5 authorizes the Legislature`s grant of jurisdiction" over
POUs.29 However, that decision concluded that Commission jurisdiction over
POUs was granted not by � 364, but by �� 8001-8057, which expressly confer
jurisdiction to regulate electric lines for public safety purposes. The Commission
26 Id. at 156, 158-59.
27 Id. at 164.
28 LADWPLADWT Opening Cmt. at 5.
29 D.98-10-059 at 3.
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reasoned that because �§ 8Q01-8Q5�were not limited to IOUs and � 364 did not
purport to restrict Commission jurisdiction, it could enforce � 364 against POUs
under �§ 8001-805�. "Moreover," D.98-10-059 noted, "the Commission's
jurisdiction is liberally canstrued" under Consumers Lobby Against Monopolies
v. Pub. UtiL Comm`n,3� and therefore "the absence of a specific statutory
authorization [did] not necessarily deprive the Commission of jurisdiction."31
As correctly noted in the Opening Brief of ORA, the Commission has
consistently affirmed its jurisdiction to regulate safety issues concerning PCJUs.
In D.98-Q3-036, the Commission held that pursuant to the Pub. Util. Code, it has
the authority and duty to regulate and enforce safety aspects of the PQUs.32
QRA contends that the CPUC subsequently affirmed this determination in
D.09-Q8-029 and D.10-Q2-034.33 In D.09-08-029, the CPUC concluded that, as a
matter of law, its jurisdiction "extends to POUs 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."34
Po1k35 provides a basis to exercise Commission jurisdiction over POUs
with respect to electric lines. In Polk, a tree trimmer was injured after a fall from
a ladder caused by an electric shock from an overhead power line with worn
insulation operated by the City of Los Angeles in its capacity as a municipal
3o Consumers Lobby Againsfi Monopolies v. Pub. Util. Comm`n,25 Cal. 3d 891, 905 (1975).
3� D.98-10-059 at 4.
32 ORA Opening Brief at 5.
33 See Id.
34 p.09-08-029, Conclusion of Law Number (No.) 3.
35 Polk v. City of Los Angeles,26 Ca1. 3d 519 (1945).
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utility.3h The overhead line was not maintained in accordance with General
Order {GO) 64-A, a predecessor to GO 95, which prescribes rules for the design,
construction, and maintenance of overhead lines.37 At trial, the implied violation
of GO 64-A was used to establish the duty of care for the municipal utility as well
as the resultant breach.38
CJn appeal before the California Supreme Court, the city argued that the
Commission lacked jurisdiction over POUs and thus its safety rules could not
prescribe POUs' duty of care. The Court conceded that, as a general matter, the
Commission did lack jurisdiction over POUs, but then praceeded to state an
exception for electric lines.
The Polk Court first observed that the predecessor statutes to �� 8002,
8003, 8037, and 8056 applied by their express terms to municipalities and
empowered the Railroad Commission (be£ore it was reconstituted as the Public
Utilities �ommission) to inspect all electric lines and "make such further
additions or changes as said commission may deem necessary £or the purposes
of safety to employees and the general public."39 The Court then noted that the
regulations which established the duty of care, GO 64-A, were promulgated
pursuant to the foregoing statutory provisions. Because '"[t]here can be no doubt
that the Legislature was empowered to pass such a statute and make it
36 Id. at 523-24.
37 Id. at 538-39.
38 Id. at 542 (Commission has"duty of making safety rules and regulations applicable to
privately owned public utilities, and it is clear that such rules and regulations establish the
standard of care . . . We can perceive of no reason why the same standard of care should not be
applicable to all utilities whether publicly or privately owned.").
39 Id. at 540.
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applicable to [POUs]" and because "danger ta the public is a matter of state
concern," POUs were subject to the Commission's rules for electric lines.40 The
Court's analysis is essentially the same as the Commission's in D.98-10-059,
which denied rehearing of the decision to apply the � 364(a) maintenance and
inspection rules to POUs.
In Polk, the Court noted that "safety rules are in reality not regulations or
the exercise of control by the commission" but are '"nothing more than safety
requirements in which the entire state has an interest."41 The Commission
reiterated that point in its conclusion about jurisdiction in D.98-10-Q59. The
Court sanctioned the use of GO 64-A to prescribe POUs' duty of care on the basis
that the Legislature had long since authorized the Commission to inspect electric
lines, including those owned by local governments, in the interest of public
safety. In Polk, the Court noted that Commission authority aver the public safety
aspects of POUs' operatzon is derived from the overriding statewide concern for
public safety. The Po�k Court found that "'the safety of overhead wire
maintenance is a matter of statewide rather than Iocal concern, the state law is
paramount."
Sections 8001-8057, read in light of the Polk decision, make �t clear that the
Commission has the authority to apply physical security rules created through
this rulemaking to the POUs. The Legislature granted the Commission the
power to make "further additions or changes as the Commission deems
necessary for the purpose of safety to employees and the general public."42 The
4o Id. at 540-41.
41 Id. at 541.
42 Public Utilities Code §� 8037, $056.
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Commission is relying on this authority to set minimum standards to ensure the
physical security of the State's electric grid, which is operated by both investor
owned utilities and publicly owned utilities.
The rationale employed by the Polk Court applies even more forcefully
in the present case, given the increased importance of electric service and the
distribution grid, and the interconnected nature of the grid. The Legislature has
directed the Commission to ensure the safety of employees and the public. That
includes not only ensurzng that wires are clear from accidental contact but also
that the electrical systems are safe £rom intentional intrusions by bad actors. As
the need to ensure the public safety of electric infrastructure is greater now, more
so than ever before, the Commission`s regulatory mandate is also
correspondingly enhanced.
. . f t lic nc r s issi
ri icti i s 1
The physical securiiy rules contemplated by the amended version of
� 364(a) are similar to the maintenance and inspection rules contained in GCa 165
and made applicable to POUs by D.98-03-036. Given this context, it is notable
that the Legislature did not insert any language in the amended version of
� 364(a) restricting the Commission's jurisdiction.
Moreover, even without � 364, the Commission has authority to make the
new physical security rules applicable to POUs, as the statutory provisions
which enabled the application of GO 64-A in Polk are virtually identical to
�§ 8001-8056.
As noted above, Sections 8037 and 8Q56 authorize the Commission to
"inspect all work" relating to surface and underground transmission and "make
such further additions or changes as the commission deems necessary for the
purpose of safety to employees and the general public.°' Section 8002 states that
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the term "`person" includes any "commission, officer, agent, or employee of this
State, or any county, city, city and county, or other political subdivision thereof,
and any other person, firm, or corporation." Based on these statutory provisions,
D.98-03-036 made GQ 165 applicable to POUs.
Sections 8001-8057 expressly apply to local government entities and
authorize the Commission to promulgate new rules to ensure the safety of
electrical lines. The mandate in � 364(a) to enforce ""inspection, maintenance,
repair, and replacement standards" is consistent with �� 8001-8057, and Polk
indicates that those statutory provisions provide sufficient statutory authority to
extend the Commission's physical security rules to POUs.
The POUs argue that the Commission's jurisdiction over them is limited
and it is inappropriate for the Commission to use statewide concerns about
safety to expand the scope of the Commission's jurisdiction.43 They do concede
that Commission decisions relating to safety may be relevant to the POUs to the
extent that they represent industry standards.44 In view of the Commission`s
mandate to ensure the safety of the State`s electric grid, the Legislature tasked it
with developing standards for the overhead and underground electrical systems.
The authorizing statutes specifically grant the Commission authority to develop
these standards and ensure compliance with them, not just by IOUs, but also the
POUs.45 The POUs state that by applying new physical security rules to them, the
43 Joint Opening Comments at 4.
44 I�
45 Public Utilifiies Code section 8002.
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Commission is encroaching on the domain of the public entities' poliee, fire and
safety departments. This argument is without merit. Precedent, public policy
considerations and longstanding Commission practice provides the Commission
with sufficient basis in this particular case to extend physical security rules to
PQUs. The Commission already possesses jurisdiction over the POUs, for the
purposes of setting, and ensuring compliance with, standards for their electrical
grids to ensure safety. The Commission does not intend in any way to usurp the
role of the public ut�lities° pol�ce, fire and safety departments. The rules set forth
in this decision are the minimum standards to ensure the physical security of the
State's electric grid. The POUs' governing bodies may, of course, prescribe
standards that go above and beyond these requirements.
The major focus of Phase I of this proceeding is to address the risks and
threats of a long-term outage to a distribution facility. Clearly, a long-term
outage at any distribution facility poses numerous sa£ety issues, whether it be at
an IOU or POU facility. The Commission was tasked with establishing industry
standards to help reduce the risk and threats of a Iong-term outage. Minimizing
the risks to distribution systems throughout the state promotes public safety and
helps to establish industry standards. Further, as the Commission noted in D.98-
10-059, electrical disruptions can affect nezghborzng utilities, regardless of their
ownership: "emergencies or power outages with a municipal utility's service
area can have effects on the State's grid that are not confined to that utility's
electric system."46 Threats to the electrical gr�d and public safety do not
discriminate based on the utility's ownership. Therefore, we conclude that it is
46 p.98-10-059 at p. 4.
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within the authority and jurisdictian of the Commission to have these standards
apply to both the IOUs and the POUs.
We now will briefly address the issues raised concerning � 2107, which
grants the Commission authority to perform investigations and levy fines against
the IOUs. It is the intention of the Commission to use Phase I of this proceeding
to establish systemwide industry standards that are aimed at addressing the
potential risks and threats associated with a long-term outage at a distribution
facility on a statew�de basis, and we are optimistic that the POUs, having
participated extensively in the proceeding, will adhere to these standards. This
proceeding is not designed to expand Commission investigatory or penalty
authority against the POUs beyond what it already possesses.
3.4. Phase II Jurisdiction
The POUs assert that neither the Pub. Util. Code nor public policy
supports the exercise of Commission jurisdiction over emergency and disaster
preparedness planning for Phase 2.
As originally enacted, � 364(b) required the Commission ta "adopt
standards for operation, reliability, and safety during periods of emergency and
disaster." However, in D.98-03-036 and D.98-07-097, the Commission clarified
that the emergency response rules could not be applied to POLTs. The
Commission concluded that because �� 8001-8057 do not relate to emergency and
disaster preparedness, those provisions do not support the exercise of
Commissian jurisdiction over POUs with respect to emergency and disaster
preparedness.
This conclusion is still sound, as � 768.6 does not evince a Legislative intent
to alter the status quo by expanding the Commission's jurisdiction. We therefore
conclude that adherence to proposed Phase II rules concerning disaster and
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emergency preparedness plans shall not be required of the POUs. Although not
bound by Commission rules pertaining to disaster and emergency preparedness
plans, the POUs are encouraged to participate in Phase II of this proceeding and
to adopt resulting best practices to the extent they find them useful and
appropriate. Consistency on a statewide level as it relates to emergency and
disaster preparedness plans is a desirable goal. POU participatian will advance
this aim.
. T it tilit r sl
Ta meet the requirements of SB 699, SED RASA conducted a series of four
physical security workshops from May to September 2017. In connection with
these four workshops, a technical working group was formed by the parties
which submitted the Joint Utility Proposal to provide guidance for compliance
with � 364.
The Joint Proposal describes how a utility shou�d establish a Distribution
Substation and Distribution Cantrol Center Security Program (Distribution
Security Program).47 The Distribution Security Program consists of the
following: 1) Identification of distribution facilities, 2) Assessment of physical
security risk on distribution facilities, 3) Development and implementation of
security plans, 4) Verification, 5) Record keeping, 6) Timelines and 7) Cost
recovery.
The following is a summary of the utility working group's Joint Proposal:
47 The Joint Utility Proposal defines Distribution Substation as an electric power substation
associated with the distribution system and the primary feeders for supply to residential,
commercial and/or industrial loads. A Distribution Control Center is defined as a facility that
has responsibility for monitoring and directing operatianal activity on distribution power lines
and Distributian substations.
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4.1. Identification
In accordance with the general direction of SB 699, the intent of the Joint
Utility Proposal is to implement a risk management approach towards
distribution system physical security, with appropriate consideration for
resiliency, impact and cost. The Joint Utility Proposal sets forth a set of general
principles that derive from information described and evaluated during the
workshops. These principles note the following:
1, Distribution systems are not subject to the same physical
security rzsks and associated consequences, includzng
threats of physical attack by terrorists, as the transmission
system.
2. Dxstribution utilities will not be able to elim�nate the risk of
a physical attack occurring, but certain actions can be taken
to reduce the risk or consequences, or both, of a significant
attack.
3. A one-size-fits-all standard or rule will not work.
Distribution utilities should have the flexibility to address
physical security risks in a manner that works best for their
systems and unzque situations, consistent with a risk
management approach.
4. Protecting the distribution system should consider both
physical security protect�on and operational resiliency or
redundancy.
5. The focus should not be on all Distribution Facilities, but
only those that risk dictates would require additional
measures.
6. Planning and coordination with the appropriate federal
and state regulatory and law enforcement authorities will
help prepare for attacks on the electrical distribution
system and thereby help reduce or mitigate the potential
consequences of such attacks.
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Consistent with these general principles, the Joint Utility Proposal suggests
various criteria to provide Operators48 with guidance needed to identify
Distribution Facilities49 requiring further assessment.
Specifically, the Jaint Utility Proposal sets forth the following as facilities
requiring such assessments:
1. Distribution Facility necessary for crank path, black start or
capability essential to the restoration of regional electricity
service that are not subject to the California lndependent
System Operator's (CAISO) operational control and/or
subject to North American Electric Reliability Corporation
(NERC) Relzabxlity Standard CIP-014-2 or �ts successors;
2. Distribution Facility that is the primary source of electrical
service to a military installation essential to national
security and/or emergency response services (may include
certain air fields, command centers, weapons stations,
emergency supply depots);
3. Distribution Facility that serves insfallations necessary for
the provision of regional drinking water supplies and
wastewater services (may include certain aqueducts, well
fields, groundwater pumps, and treatment plants);
4. Distribution Fac�lity that serves a regional public safety
establishment (may include County Emergency Operations
Centers; county sheriff's department and major city police
department headquarters; major state and county fire
service headquarters; county jails and state and federal
prisons; and 911 dispatch centers);
5. Dzstribut�on Fac�lity that serves a major transportation
facility (may include International Airport, Mega Seaport,
48 An Operator is an Electrical Corporation, a Local Publicly Owned Electric LJtility, or an
Electrical Cooperative responsible for the reliability of one or more Distribution Facilities.
49 A Distribution Substation or Distribution Control Center.
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other air traffic control center, and international border
crassing);
6. Distribution Facilzty that serves as a Leve11 Trauma Center
as designated by the Office of Statewide Health Planning
and Develapment; and
7. Distribution Facilzty that serves over 60,000 meters.
4.2. Assessment
After the Operator has identified any Distribution Facility requiring
additional assessment ("Covered50 Distribution Facility"), the operator will
conduct an evaluation of the potential risks associated with a successful physical
attack on such a facility or facilities and whether existing grid resiliency,
requirements for customer-owned back-up generation and/or physical security
measures appropriately mitigate identified risks, In doing so, the Operator may
consider the following:
2. The existing system reszliency and/or redundancy
solutions (e.g., switching the load ta another substation or
circuit capable of serving the load, temporary circuit ties,
mobile generation and/or storage solutions);
2. The availability of spare assets to restore a particular load;
3. The existing physical security protections to reasonably
address the risk;
4. The potential for emergency responders to identify and
respond to an attack in a timely manner;
5. Location and physical surroundings, including proximity
to gas pipe�ines and geographical challenges, and impacts
of weather;
50 "Covered" is the utility working group term employed to describe those assets that are
applicable, or that should be subject ta physical security. We wi11 employ this term for the
length of this decision for the sake of consistency.
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6. History of criminal activity at the Distribution Facility and
in the area;
7. The availability of other sources of energy to serve the load
(e.g., customer owned back-up generation or storage
solutions);
8. The availability of alternative ways to meet the health,
safety, or security; and
9. requirements served by the load (e.g., back up command
center or water storage facility).
4.3. Mitigation Plan
In arder to address the risk of a long-term outage ta a Covered
Distribution Facility due to a physical attack, each Operator will develop and
implement a Mitigation Plan51. The Operator should have discretion to select the
specific security measures that are most appropriate for the Covered Distribution
Facility, The Mitigation Plan will include consideration of the costs assoc�ated
with any physical security improvements. In developing the Mitigation Plans,
the Operator may also consider local geagraphy and weather, engineering
judgment and its own experience.
In developing Mitigation Plans, Operators may use risk-based
performance standards to identify the means by which a Covered D�stribution
Facility's security can be upgraded (e.g., perimeter security, improved
monitoring) and its resiliency improved (e.g., timely access to spare equipment,
the ability to serve in whole or in part from another facilzty or circuit, back-up
generation or storage). A performance standard specifies the outcome required
51 The documentation of a risk-based strategy for mitigating the impacts of a physical attack on
a Covered Distribution Facility. The strategy may cor�sist of operational reszliency measures or
physical security measures.
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but leaves the specific measures to achieve that outcome up to the discretion of
the C)perator. The goal in this case is to reduce the risk and/or consequences of a
successful physical attack on a Covered Distribution Facility and provide a
variety of solutions to mitigate the risk and/or consequences and achieve the
goal.
Examples af potential resiliency and security solutions that could be
deployed to ad dress identified risks and are not meant to be binding or definitive
or to be required for any particular Distribution Faczlity include, but are not
limited to:
Examples of Potentxal Resiliency Solutions:
1. Strategically Located Spares - Strategically locate spare
equipment to facilitate the repair of a Covered Distribution
FaClTlty;
2. Distributzon Resiliency Upgrades - Adding circuit ties or
other facilities to enhance the ability to switch around
damaged facilities to facilitate the repair and restoration of
service;
3. Enhanced Resiliency Response - Develop response
strategies for temporarily restaring service {e.g., mobile
generation/storage, jumper from an adjacent circuit};
Examples of Potential Security Solutions:
1. Access - Measures to limit unauthorized entry or breach of
the facility (e.g., fencing, gates, barriers or other security
devices);
2. Deterrent - Measures to discourage unauthorized entry or
breach of the facility (e.g., cameras, lights); and
Coordination - Measures to further collaborate with law
enforcement as appropriate.
. . rific ti
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In order to evaluate each Mitigation Plan(s), each Operator will select an
unaffiliated third party with the appropriate experience needed to review the
Identification and Assessment evaluations and the Mitigation Plan(s) performed
and developed by the Operator. After the Mitigation Plans have been evaluated,
the Operator should either modify its Mitigation Plan to be consistent with the
recommendations or document its reasons for not doing so.
4.5. Records
Adequate record retention is important to ensure each utility's Mitigation
Plan is successful. Electronic or hard copy records of the Distribution Security
Program implementation will be retained for not less than five (5) years. �uch
records are extremely confidential and will be maintained in a secure manner at
the Operator's headquarters. The recorcls maintained by an Operatar will be
available far inspection at its headquarters ar San Francisco offices by
Commission staff upon request.
Electronic or hard copy records of the Operator's Distribution Security
Program Implementation will include, at a minimum:
1) The Operator`s Identificat�on of Distribution Facilities
requiring further assessment;
2) Each Operator`s Assessment of the potential threats and
vulnerabilities of a physical attack and whether existing
grid resiliency, customer-owned back-up generation
and/or physical secur�ty measures appropriately mitigate
the risks on each of its identified Distribution Facilities;
3) Each Operator's Mitigatian Plans covering each of its
Covered Distribution Facilities under Section 4;
4) The unaffiliated third-party evaluation of the Qperator`s
Identification and Assessment evaluations and Mitigation
Plans performed and developed by the Operator� and
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5) If applicable, the Operator's documented reasons for not
modifying its Mitigation Plans consistent with the
unaffiliated third-party's evaluation.
. . i li r c
Any Operator that has identified at least one Distribution Facility
requiring further assessment whose risks are not found to be appropriately
mitigated during the verification phase will complete an initial draft of its
Mitigation Plan(s}, within eighteen (18) months from the effective date of these
guidelines.
Where the Operator is required to seek verification, the Operator will
obtain an unaffiliated, third-party review within twenty-seven (27) months from
the effective date of these guidelines. Each Qperator will meet all obligations set
out in this decision within thirty (30) months of the effective date of these
guidelines.
4.7. Gost52
The IOUs propose that at its discretion, the Operator may establish an
account to track the expenditures associated with the development and execution
of its Distributian Security Program. IOUs request authorization to file Tier 1
Advice Letters far this purpose. Electrical Cooperatives and POUs wauld act in
accordance with any processes established by a governing or other type of baard
with the requisite authority.
IOUs also recommend that they be authorized to file separate applications
or GRC requests for the recovery of costs associated with their respective
52 The issue of costs discussed in this section are the positions advanced by the IOLJs. We
decline to ixnplement the cost recovery measures suggested by the IOUs. Rather, they will
follow the cost recovery methods as set forth in Section 6.8 below.
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Distribution Security Programs. Although the Distribution Security Program
documents are considered security-sensitive information and cannot be filed as
supporting documentation, the IOUs may file a publie version of the unaffiliated
third-party review and Commission approval in support of their recovery
requests.
5. SED RASA Staff Evaluation of Joint Utility Proposal,
rit I 1 t c fii s
Four workshops were conducted during Phase I of this proceeding. The
first three workshops identified and explored the regulatory framework that
currently exists for assessing physical security and how new regulations could be
drafted. The utilities presented the Joint Utility Proposal at the fourth workshop.
In addition to being actively involved with the workshops, SED RASA
analyzed the Joint Utility Proposal and made various recommendations. This
analysis was made available ta the parties on January 16, 2018 within a ruling by
the assigned ALJ. The parties filed bath comments and reply comments on SED
RASA's evaluation. SED RASA thoroughly considered all camments and reply
comments, and in response undertook additianal evaluation, and revisited its
original set of recommendations.
The Joint Utility Proposal would introduce new requirements covering
electric assets that support distributian-level service within California's
regulatory and safety jurisdictian. These assets, largely substations and control
centers, do not typically rise to the level of critical infrastructure as defined in the
federal Critical Infrastructure Protocols (CIPs). Yet, they are essential for
providing reliable energy to residential, commercial and industrial loads.
In addition to the new rules and measures articulated by the Joint Utilities in
their Proposal, as outlined in Section 4 above, SED RASA recommends
additional new rules and measures, and guiding principles, above and beyond
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those outlined in Section 4, to further strengthen the Joint Utility Proposal. These
items are detailed below.
6. Guiding Principles ofi California
I cfiri sic 1 c rifi
1) Costs of incremental physical security measures should be
reasonable, controlled, and weighed against potential
benefit, so they do not result in a burden to ratepayers.
2) Opportunities to incorporate high-benefit, low-cost
measures should be captured, particularly at the time o£
new or upgraded substation construction.
3) Distribution assets should be hardened or deszgnated with
consideration for ensuring service integrity to essential
customers, among other factors identified in the Joint
Proposal.
4) Resiliency strategies to ensure that priority distribution
assets, particularly fhose tied to service of essential
custamers remain in service and are able to rapidly recover
from an unplanned service outage should be considered an
equally effective response to addressing physicai security
risks.
.1. i - t rce r t rs
tilities' istri ti ss ts
SED RASA recommends the following six-step procedure for carrying out
new physical security plan requirements to address utilities° distrrbution assets.
These proposed steps are mode�ed on the security plan requirements set forth by
NERC CIP-014.
This six-step plan is as follows:
Step 1. Assessment. Drafting of a plan, addressing
prevention, response, and recovery, which could be prepared
in-house or by a consultant, and which shall include proposed
and recommended mitigation measures.
Step 2. Independent Review and Utility Response to
Recommendations. Proposed plan would be reviewed and by
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an independent third party, likely a qualified consultant
expert, national laboratory, or a regulatory or industry
standard body (such as the Electric Power Research Institute).
Step 2 would include reviewer recommendations that assess
and appraise the appropriateness of the risk assessment,
proposed mitigation measures, and other plan elements. A
utility would be expected to fully address reviewer
recommendations, including justifying any mitigations that it
declines to accept; the independent third-party
opinion/recommendations, utility response, threat and risk
assessment, and mitigation measures combined wou�d
constitute a final plan report.
Step 3. SED Review (for IOUs only�. Final plan report would
be reviewed by the CPUC SED (recurring every five years)j3
so as to determine whether it is in compliance with regulatory
requirements, and eligible to request funding for
implementation. Upon five years from the date of adoption, a
utility would be required to have any revised or original plan
updated and repeat the review process. Utilities may be
afforded regulatory relief by way of an exemptzon request
process for special cases where undertaking of the plan
overhaul and/or review process may be impracticalale or
unduly burdensome. Non-compliance could result in an
enforcement action, potentially resulting in sanctions and/or
penalties as provided by PU Code Sec. 364(c). An SED
finding of compliance would render IOUs eligible to request
funding for appropriate physical security needs identified by
IOUs; project expenditures would be tracked in a
memorandum account and subject to reasonableness review
in the GRC.
53 This time interval is based on the requirements instituted for the City of Los Angeles under
City Charter.
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Ste� 3a. Plan Review (for POUs onl�}. Final plan report
would be deemed adequate (recurring every five years, and
eligible for same exemption request process made available to
the IOUs) by a qualified authority designated by the
applicable local governance body. (For example, Riverside
Public Utilities currently develops a security and emergeney
response plan that conforms to the Governor's Office of
Emergency Services (CaIQES) and Federal Emergency
Management Agency (FEMA) standards and receives their
endorsement.)
Step 4. Adoption (for POUs onlv). Reviewed plan would be
submitted to the appropriate regulatory oversight body (local
governance body) for review and greenlighting (adoption),
Step 4 should include funding to implement the plan.
Step 4a. Notice, (for POUs only�. Provide CPUC with official
notice (ideally including a copy of a resolution of the adopted
plan action.
Step 5. Maintenance. Ongoing adopted plan refinement and
updates as appropriate and as necessary to preserve plan
integrity. All security plans should be concurrent with and
integrated into utility resiliency plans and activities.
Step 6. Repeat Pracess. Plan overhaul and review every five years.
For now, the Commission finds the process described above, adequate.
Shou�d the Commission subsequently find that a more structured and formal
process of Security Plan approval is desirable or changes to the Security Plans
themselves, the Commission could make such determination via resolution ar a
decision based upon a developed record. Changes to Security Plan requirements
may also be done by SED (or successor entity) director letter.
6.2. Additional Requirements for Mitigation Plans
These additional requirements are:
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1. Galifornia electric utilities shall, within any new or
renovated distribution substation, incorporate and design
their facilities to incorporate reasonable security features.
2. Utilities' security plans shall include a detailed narrative
explaining how the utility is taking steps to implement:
(a) An asset management program to promote
optimization and quality assurance for tracking and
locating spare parts stock, ensuring availability and the
rapid dispatch of available spare parts;
(b)A robust workforce training and retention program to
employ a full roster of highly-qualified service
technzcians able to respond to make repairs in short
order throughout a utility`s service territory using spare
parts stockpiles and inventory;
(c) A preventative maintenance plan for security
equipment to ensure that mitigation measures are
functional and perfarming adequately; and,
(d)A description of Distribution Control Center and
Security Control Center roles and actions related to
distribution system physical security (this item would
be for IOUs only).
. .1. iti I ti I ir ts f r
iti ti I s
The Commission highly encourages and recommends the following
optional security measures and best practices:
1. A training program for appropriate local law enforcement
and utility security staff to optimize communication
during a physical security event. Training for law
enforcement should include information on physical
infrastructure and relevant utility operations;
2. A determination of the vulnerability of any associated
communication utility infrastructure that supports priority
distribution assets, which if deemed to be vulnerable,
should have appropriate mitigation measures prescribed;
and
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3. Incorporating into applicable new and renovated or
upgraded utility faeilities design Features that promote a
sense of order and ownership, increase surrounding
visibility and sightlines, capture opportunities for
defensibility, and confound intrusion attempts by delaying
and frustrating attackers via strategic placement of assets.
These concepts, well-established within and embraced by
the power industry and other applications, are encouraged
and called out by NERC within CIP-014 guidelines as
Defense in Depth and Community Protection through
Environmental Design.
issi fi t t t iti n I s r I
potential for increasing grid resilience and reliability, but
cli t t i ti t t s r li t r ,
recognizing the utilities' work ahead to master new physical
security regulations and complete their first iteration of
iti ti I s I r rts. . . ir - rific ti
As noted in Sectian 6.1 above (°°Step 2. Independent Review and Utility
Response to Recommendations"), a required third-party review shall occur in
tandem with completion of a list of reeommended mitigation measures.54 The
third-party reviewer shall prepare recommendations on appropriate mitigation
measures and/or a statement supporting or rejecting proposed mitigation
measures. This statement shall contain justification for the acceptance or
rejection of each proposed mitigation measure.
Each utility shall produce a response to these proposed mitigation
measures and the third-party expert's opinion ancl recommendations, indicating
whether it concurs or disagrees, and whether a gzven mitigation measure will be
implemented, or is declined. Utilities shauld provide a justification for declining
any proposed mitigation measures.
54 This original plan and the third-party review may collectively be called the Mitigation Plan.
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A utility's risk-threat assessment, mitigation plan, consultant appraisal and
statement, and utility response, would together comprise its Security Plan
Report. The Security Plan should include an estimated timeframe for how long it
wi11 take to implement the Mitigation Plan and a cost estimate for incremental
expenses associated with implementing the Mitigation Plan.
6.4. Third-Party Expert Qualifications
Each utility shall employ a qualified third-party expert to provide
independent verification of any Distribution Security Program and Mitigation
Plans, taking the following requirements into account:
Unaffiliated Third-Party Reviewer: The Unaffiliated
Third-Party Reviewer shall be an entity other than the
Operator with appropriate expertise, as described below. The
selected third-party reviewer cannot be a corporate affiliate of
the Operator (i.e., the third-party reviewer cannot be an entity
that is controlled by the utzlity or controlled by or is under
common control with, the Operator), A third-party reviewer
also cannot be a division of the Qperator that operates as a
functional unit. A governmental entity can select as the
third-party reviewer another governmental entity within the
same political subdivision, so long as the entity has the
appropriate expertise, and is not a division of the Operator
that operates as a functional unit, i.e., a municipality could use
its police department as its third-party reviewer if it has the
appropriate expertise.
Unaffiliated Third Party Reviewer Appropriate Expertise:55 The
Unaffiliated Third-Party Reviewer shall be an entity or organization with
electric industry physical security experience and whose review staff has
appropriate physical security expertise, i.e., have at least one member who
holds either an ASIS International Certified Protection Professional (CPP)
55 Unaffiliated Third-Party Reviewer Appropr�ate Expertise can be established by any of these
methods.
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or Physical Security Professional (PSP) certification; an entity or
organization with demonstrated law enforcement, government, or military
physical security expertise; or an entity or organization approved to do
physical security assessments by the CPUC, Electric Reliability
Organization or similar electrical industry regulatory body.
. . cc ss fi I f r ti
The Cammission is currently engaged in an effort to update its policies
regarding the protection of confidential information in a rulemaking related to
Public Records Act requests.5h Additionally, a recent decision appraved an
update to General Order 66-D, which took effect in January 2018, The utilities in
their Joint Proposal and in comments have advocated for the use of a Reading
Room approach that would require that Commission staff visit IOU property to
view physical security-related information that they consider to be highly
confidential, or at a level of sensitivity which utilities believe Commission
confidentiality rules and provisions are unequipped to address.
Commission staff, in the caurse of carrying out Phase I of this proceeding,
report having tested the Reading Room approach with mixed results.
Commzssion staff report having visited utility offices to obtain data and v�ew
documentation previously denied by investor owed utilities in response to data
requests. Commission staff's complaint with the Reading Room approach is they
were not allowed by the utilities to engage in notetaking or any other means of
keeping records of documents made available in the Reading Room.
The Commission recognizes that the Reading Room approach by nature
entails certain limitations on Commission staff's ability to freely and
56 R.14-11-001, Order Instituting Rulemaking to Improve Public Access to Public Records
Pursuant to the Cal'zfornia Public Records Act.
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independently review and assess utility documents utility reports and
submittals.
For these reasons, we have concerns about relying on the Reading Room
approach as the sole means for accessing tztility information necessary to gauge
whether utilities are in compliance with this decision's provisions for producing
and furnishing the Commission with recurring regulatory compliance reports
and ongoing updates.
Parties including SED Advocacy and ORA recommend making the
Reading Room approach temporary, while the utilities recommend that it be
designated permanent status.
We conclude that neither recommendation fully satisf�es the need to
conveniently access regular regulatory filings. At the same time, we are mindful
of the concerns raised by the utilities regarding sensitive physical security-
related information.
We therefore bifurcate utility physical security-related informatzon into
two categories for the purposes of Commission staff access and the transfer of
data:
• Category 1 - informatian that is specifical�y required to
reviewed by the Commission in this decision ("routine
regulatory compliance f�lings)�°' and
• Category 2 - other information which Commission staff
may request of utilities from time to time ("ad hoc
information").
Category 1 routine regulatory compliance filings will not be subject to the
Reading Room approach and shall be provided to SED staff by means of
transmittal to the Cammission. Category 2 ad hoc information shall be subject to
the Reading Room approach.
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The Commission adopts the Reading Room approach as an interim
solution pending the ongoing R.14-11-OQ1 rulemaking establishing new rules for
the safekeeping, sharing, transmittal, and inspection of confidential information.
The Commission intends to monitor the effectiveness of the Reading Room
approach, and review and revise the approach as needed.
The Reading Room approach shall entail utility information being made
available to Commission staff on utzlity property at a location convenient and
agreed to by CPUC staff.
It remains without question that the Commission and its staff require and
are fully entztled to access to such znformation, as long as protections agaznst
public release are maintained. Especially in cases where the Commission is
investigating an incident (whether it is already defined in our regulations or a
new aspect, such as physical or cyber-attack), access to records shall be provided
promptly upon the Commission request.
It should be noted that the Reading Room approach only relates to how
the Commission may access confidential utility information relating to physical
security, and that utilities still are required to first justify confidentiality claims
relating to aIl information being made applicable to the Reading Room approach
as per generally applicable Commission requirements.
Additionally, nothing in the present decision establishes a basis for utilities
to restrict access to any information that is publicly accessible pursuant to
Commission rulings, orders, or other actions. To the extent that utilities believe
that restricting public access to any category of information that is publicly
available is necessary for mitigating physical security risks to a Covered
Distribution Facility, they should describe and justify any restrictions on
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information access they propose within their Mitigation Plans for any affected
Covered Distribution Facilities,
6.6. Timeline for Implementation
Security Plans shall be completed in accordance with the following criteria:
1. Each utility's Security Plan Report is due to the CPUC
within 30 months of the approval of this decision; and
2. POUs only — Within 30 months of the approval of this
decisian, the POUs shall provide the Director of Safety and
Enforcement Division and the Director of the Energy
Division with notice of the plan adoption by way of copy
of a signed resalution, ordinance or letter by a responsible
elected- or appointed official, or utility director. If a POU
has an exzsting security plan that has been adopted by its
Board of Directors or City Council within three years prior
to the date of this decision, the requirement to have a p�an
adopted may be waived by the Commission.
.7. i
Utilities sha�l provide to the Director of the Safety and Enforcement
Division and the Director of the Energy Division copies of all 0E-417 reports
submitted to the U.S. DOE within two weeks of filing with U.S. DOE.
All utilities except SDG&E objected to SED RASA's recommendation of
annual reporting, citing a preference for data requests as the appropriate vehicle.
We disagree that the responsibility to be made aware of any incidents should fall
on the Commission. Additionally, such an annual reporting requirement is
enshrined into law per § 590 of the Pub. Util. Code. Therefore, and in order to
ensure statewide consistency, we require the utilities to submit an annual report.
These annual reports shall be submitted to the Director of the Safety and
Enforcement Division and the Llirector of the Energy Division by March 31 each
year, commencing in 2020. Each report shall include a section that describes any
physical security incident resulting in a utility insurance claim. The Commission
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does not require copies of filed insurance claims or specifics of asset vulnerability
that allowed for a physical security breach. Rather, the submittal should be a
high-level report. Utilities should make mention of any incidents reported for
insurance claims within the annual reporting period of Apri11 to March 31 and
include such general information as location, and impaet af the incident, and
monetary value of claim. Filing should include a data file (in Microsoft Excel
format). As with all Commission filings, should utilities believe that certazn
information is sensitive, they must follow GO 66-D requirements for identifying
confidential information.
To meet the reporting requirement introduced in SB 699 in Pub. Util. Code
� 364 (b) now located in � 590, these annual reports should also include any
significant changes to the Security Plan Reports (including new facilities covered
by the Plan or major mitigation upgrades at previously identified facilities).
8ecause the statutory language provided that these be publicly available, the
utility may provide both a complete report for the Commission and an
appropriately redacted version for the public to be posted on the Commission's
web site.
. . t ec v r
The Joint Utilities propose that they should be authorized to file separate
applications to request recovery of the costs associated with their Distribution
Security Programs. We disagree that the electric utilities should be authorized to
file separate applications to request recovery of costs associated with their
respective Distribution Security Programs. Utilities may establish a
memorandum account to track associated costs. However, cost recovery
requests shall be mad� in each utility's general rate case (GRC).
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Electrical Cooperatives and PQUs should act in accordance with processes
established by a governing or other type of board with the atzthority to approve
such proeesses, if any.
T. Commission Position on Joint Utility Proposal
c ti s
The Commission finds that the elements of the Joint Utility Proposal set
forth in the mitigation plans represent a first-of-its kind effort at the state level,
and yet they do not go far enough to prescribe reasanable physical security
measures. Additionally, the Commission finds that the SED RASA
recommendation to include additional requirements is sound and advisable. We
find that the Joint Utility Proposal, augmented by all of the above additional
measures and clarifications as recommended by SED RASA57 strike the right
balance between achieving grid protection and keeping electricity service
affordable. As such, the Commission finds adoption of the combined provisions
of Sections 4 and 6 outlined above, will provide an appropriate level o£ physical
security and ensure California grid resilience should another Metcalf-type
sabotage event target the state's electric utilities' distribution infrastructure.58
57 SED RASA recommendations for additional measures consist of the following:
6.0 Guiding Principles of California Electric Physical Security
6.1Six-Step Procedure to Address Utilities' Distribution Assets
6.2.1 Additional Optional Requirements for Mitigation Plans
6.2 Additional Requirements for Mitigation P1ans
6.3 Third-Party Verification
6.4 Thzrd-Party Expert Qualifications
6.5 Access to Infarmation
6.6 Timeline for Implementation
6.7 Reporting
6.8 Cost Recovery
58 Should there be any question of which sha11 predominate should there be any zncongruity
or conflict between a utility or SED RASA recommended rule, the SED RASA rule shall apply.
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In closing, the Commission notes that it is desirable that California's
electric utilities coordinate to the fullest extent practicable to exchange
information and best practices that advance the State's safety, security, and
resilienee goals. To this end, all utilities will be expected to relay information
about critical loads within a service territory to any other utility in California
whose distribution facilities also are used to supply electricity for those critical
loads.
8. Safety Considerations
Safety is a major concern for the Commission. The Commission's safety
goals are furthered by ensuring all California electric utilities have identified
priority distribution assets that merit special protection, and prescribing
measures to reduce risks and threats to these assets.
. cl si
Phase I of this proceeding requires electric utilities to identify electric
supply facilities which may require special protection and measures to identify
risks and threats. Each Operator will develop and implement a six-step
Mitigation Plan modeled on the security plan requirements set forth by NERC
CIP-014, The safety and security benefits promoted by these Mitigation Plans
mandate that the POUs also comp�y with these requirements as set forth in this
decision.
1 . t ri
The proposed decision in this matter was mailed in accordance with � 311
of the Pub. Util. Code and eomments were allowed under Rule 14.3 of the
Commission's Rules of Practice and Procedure. Comments were filed on
November 29, 2018, by PG&E, SCE, SDG&E, CMUA/LADWP/SMUD and SED
Advocacy, and reply comments were filed on December 4, 2018 by PG&E, SCE,
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�DG&E, CMUA/LADWP/SMUD, SED Advocacy and ORA, filing as the Public
Advocates Offiee.
In their comments the utilities sought greater conformity with the original
Joint Utility Proposal, particularly in the proposed timeline for compliance, and
argued against the requirements in the Plans regarding asset management,
workforce training, and preventative maintenance planning going beyond
federal CIP-014 requirements, recommended by SED RASA. SED Advocacy
sought to make mandatory certain optional aspects of the RASA recommended
changes to the Joint Utility Proposal. SCE sought to eliminate certain
requirements for submitting confidential information in their plans to the CPUC
for staff validation and to make the Reading Room approach to access to
sensitive data a permanent feature. POUs expressed concerns about sharing
information about critical loads among adjacent utilities, and sought clarification
of defznitions of physical security incidents reported in the federal 0E-417
reports.
The Commission finds it reasonable to adopt the compliance t�melines
initially expressed in the Joint Utility Proposal and has clarified some of the
requirements for providing the Commission with plans and reports in the body
of this decision. Additionally, the proposed decision that was initially mailed for
comment included an Appendix. Upon further review, we have decided to
remove the Appendix from the final decision. Other proposed changes are not
adopted.
11. Assignment of Proceeding
Clifford Rechtschaffen is the assigned Commissioner and Gerald F. Kelly is
the assigned Administrative Law Judge to the proceeding.
Findings ofi Fact
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1. SB 699 directs the Commission to develop rules for addressing physical
security risks to the distribution systems of electrical corporations.
2. AB 1650 directs the Commission to develop emergency preparedness
plans applicable to electrical corporations and water companies regulated by the
Commission.
3. This proceeding will be conducted in two phases.
4. Phase I of this proceeding pertains to the requirements set forth in SB 699.
5. Phase II of this proceeding pertains to the requirements set forth in
AB 1650.
6. Ensuring the physzcal security of all electrical supply systems is of great
importance to the Commission.
7. Ensuring the physical security of all electrical supply systems within the
state will help maintain high quality, safe and reliable service.
8. Four Phase I physical secur�ty workshops were conducted by SED RASA
from May to September 2017.
9. During these workshops, a technical working group was formed by the
utilities.
10. As a result of technical working group discussions, the utilities submitted
a Joint Utility Proposal.
11. The Joint Utility Proposal offered gu�dance for compliance w�th SB 699,
and represented a first-of-its-kind effort to establish new critical asset protections
at the distribution level.
12. The Joint Utility Proposal (at 4.1.6 and 4.3.3 above} provided assurance
that IQUs and PQUs would partner with law enforcement agencies broadly to
plan, coordinate, and share information to ensure safety, resilience, and security.
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13. The Commission expects that all California utilities will communicate,
coordinate, and share best practices with Iaw enforcement and each other, as
appropriate to advance, local, State, and Federal safety and security goals.
14. SED RASA evaluated the Joint Utility Proposal and identified areas where
the praposed security plans could be improved.
15. Review of the Distribution Security Plans (Security Plans and its
components are the process of drafting the Mitigation Plan) and Mitigation P1ans
(Mitigation Plans are the plans that are ultimately adopted) by independent thzrd
parties will help to strengthen these plans.
16. Ensuring that confidential security information is not released to the
public is of great importance to the Commission.
17. The Commission is currently engaged in an effort to update �ts policies
regarding the protection o£confidential information in a rulemaking related to
Public Record Acts Requests in R.14-11-001.
18. D.17-09-023, which became effective on January 1, 2018, updated GO 6f D
as it relates to submission of confidential information to the Commission.
19. The Commission and its staff are fully entitled to access confidential
information, as long as protectians against public release are maintained.
20. The Commission recogn�zes that the Reading Room approach advanced
in the Joint Utility Proposal is imperfect, with SED staff reporting inconsistency
statewide, and issues and concerns with its ease, practicality, usefulness, and
timeliness in their experience with testing it in the course of carrying out this
proceeding.
21. The Commission recognizes that the Reading Room approach by nature
entails certain limitations on Commission staff`s ability to review IOU
documents, which may not afford notetaking or records retention all and any of
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which may render arduous and impractical its usage for the purposes of
reviewing recurring and routine required submittals described within this
decision.
22. The Commission therefore determines that ifi is not desirable to apply the
Reading Room approach to recurring and routine required IOU submittals and
updates described within this decision (i.e., Physical Security Plan Reports and
Drafts, Mitigation Measures and Consultant-prepared documents, Annual
Reporting, and 0E-417 Reports).
23. The Commission adopts the Reading Room approach as an interim
solution to the handling and sharing of other physical security data requested by
Commission staff on an ad hoc basis, allowing Commission staff to review
documents at a utility property location convenient to and agreed to by CPUC
staff such as the utility's San Francisco office address.
24. The Reading Room approach sha11 be superseded by outcomes in the
ongoing R.14-11-001 rulemaking.
25. It zs important to maintain uniformity at a statewide level as it relates to
ensuring the physical security of the electrical distribution system.
26. It is reasonable that Step 2 of the Six-step Plan Process require that an
independent third-party review a utility`s physical security plan to assess and
appraise the sufficiency of the risk assessment, proposed mitigation measures,
and other plan elements and make recommendations regarding the plan
elements.
27. It is reasonable that Step 3a of the Six-step Plan Process require that the
POUs provide the Commission with notice of successful completion of their
Security Plan review and adoption.
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28. It is reasonable that all California electric utilities be required, within any
new or renovated distribution substation, to design their facilities to incorporate
reasonable security features.
29. It is reasonable that all California electric utilities be required to include
within their security plans a detailed narrative explaining how the utility is
taking steps to implement:
a) An asset management program to promote optimization
and quality assurance for tracking and locating spare
parts stock, ensuring availabi�ity and the rapid dispatch
of available spare parts;
b) A robust workforce training and retention program to
employ a full roster of highly-qualified service
technicians able to respond to make repairs in short order
throughout a ut�lity's service terrztory using spare parts
stockpiles and inventary;
c) A preventative maintenance plan for security equipment
to ensure that mitigation measures are functional and
performing adequately; and,
d) A descr�ption of Distribution Control Center and Security
Control Center roles and actions related to distribution
system physical security (this item (d} would be required
for IOUs only).
30. It is reasonable to expect California's electric utilities to coordinate with
one another to the fullest extent practicable, and to relay infarmatian about
critxcalloads within a serv�ce territory to any other utility in the state whose
distribution£acilities also are used to supply electricity for those critical loads.
Conclusions of Law
1. SB 699 confers on the Commission authority to develop rules for
addressing the physical security risks to the distribution systems of electric
corporations.
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2. AB 1650 confers on the Commission authority to develop rules for
emergency preparedness plans applicable to electrical corporations and water
companies regulated by the Commission.
3. This decision fulfills the mandates of SB 699.
4. The decision in Phase II of this proceeding will fulfill the mandates of
AB 1650.
5. Pursuant to �� 8001 to 805� of the Pub. Util. Code, the Commission has the
authority and duty to regulate and enforce safety aspects of POUs.
6. Sections 8001-8057 of the Pub. Util. Code provide that the Commission has
juriscliction over the public safety aspects of POUs,
7. The need to ensure the safety and security of the electrical dzstribution
system mandates that Phase I of this proceeding be applied to both IOUs and
POUs.
8. This decision should be effective today.
O R D E R
IT IS E E that:
1. Within 18 months of this decision being adopted, Pacific Gas and Electric
Campany, San Diego Gas & Electric Company, Southern California Edison,
PacifiCorp, Bear Valley Eiectric Service, and Liberty CalPeco shali prepare and
submit to the Commission a preliminary assessment of priority facilities for their
distribution assets and control centers.
2. Within 30 months of this decision being adopted, Pacific Gas and Electric
Company, San Diego Gas & Electric Company, Southern California Edison,
PacifiCorp, Bear Valley Electric Service, and Liberty CalPeco shall submit each
utility's Final Security Plan Report.
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R.15-Q6-009 COM/CR6/avs
3. Within 30 manths of this decision being adopted, the Publicly Owned
Utilities shall provide the Commission with notice of final plan adoption.
4. The Publicly Owned Utilities' notice of final plan adoption may consist of a
copy of a signed resolution, ordinance or letter by a responsible elected- or
appointed official, or utility director.
5. AIl California Electric Utility Distribution Asset Physical Security Plans
shall conform to the requirements outlined within the Joint Utility Proposal, as
modified by thxs deciszon (rules and requirements collectively known as
"security plan requirements"}.
6. The Investor CJwned Utilities and Publicly Owned Utilit�es sha11 adhere to
the Safety and Enforcement Division`s Six-step Security Plan Process.
7. The Six-step Plan Process consists of the following: Assessment;
Independent Review and Utility Response to Recommendations; Safety and
Enforcement Division Review (for Investor Qwned Utilities s); Local Plan Review
(£or Publicly Owned Utilities); Maintenance and Plan overhaul/new review.
8. Subsequent changes to the security plan requirements deemed beneficial
and necessary, shall be enabled by one o£ the following: 1) Commission
Resolution or Decision; 2) Ministerially, by Safety and Enforcement Division (or
successor entity) director letter.
9. In carrying out any future changes to the security plan requirements,
Safety and Enforcement Division shall confer with utilities about any
recommended modifications to the plan requirements.
10. Prior to the submittal of the Security Plan, Pacific Gas and Electric
Company, San Diego Gas & Electric Company, Sauthern California Edison,
PacifiCorp, Bear Valley Electric Service, and Liberty CalPeco shall each have
their respective plan reviewed by an unaffiliated third-party entity.
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R.15-Q6-009 COM/CR6/avs
11. The unaffiliated third-party reviewer shall have demonstrated
appropriate physical security expertise.
12. California electric utilities shall, within any new or renovated distribution
substation, design their facilities to incorporate reasonable security features.
13. Utility security plans shall include a detailed narrative explaining how
the utility is taking steps to implement an asset management program to
promate optimization, and quality assurance for tracking and locating spare
parts stock, ensuring availabzlity, and the rapid dispatch of available spare parts.
14. Utility security plans shall include a detailed narrative explaining how
the utility is taking steps to implement a robust workforce training and retention
program to employ a full roster of highly-qualified service technicians able to
respond to make repairs in short order throughout a utility`s service territory
using spare parts stockpiles and inventory.
15. Utility security plans shall include a detailed narrative explaining how
the utility is taking steps to implement a preventative maintenance plan for
security equipment to ensure that mitigation measures are functional and
performing adequately.
16. Utility security plans shall include a detailed narrative explaining how
the utility is taking steps to implement a description of Distribution Control
Center and Security Control Center roles and actions related to distribution
system physical security.
17. Pacific Gas and Electric Company, San Diego Gas & Electric Company,
Southern California Edison, PacifiCorp, Bear Valley Electric Service, and Liberty
CalPeco sha11 each document all third-party reviewer recommendations, and
specify recommendations that were accepted or declined by the utility.
_�2 _
R.15-Q6-009 COM/CR6/avs
18. Pacific Gas and Electric Campany, San L?iego Gas & Electric Company,
Southern California Edison, PacifiCorp, Bear Valley Electric Service, and Liberty
CalPeco shall each provide justification supporting its decision to accept or
decline any third-party recommendations.
19. Physical Security-related information is bifurcated into two categories.
Recurring and routine utility compliance work products and ongoing utility
updates required by this decision are not subject to the Reading Room approach
but shall be transmitted to the Commission. All other physical security data
requested by Commission staff on an ad hoc basis sha11 be made available to the
Commission on utility property in a manner agreed to by the Safety and
Enforcement Division, or its successor, until such time that the Commission
finalize� its rules for the handling, sharing, and inspection of confidential
information.
2Q. If a Publicly Owned Utility has an existing blanket Security Plan that has
been adopted by its Soard of Directors or City Counc�l within three years prior to
the date of this decision, the requirement to have a plan adopted may be waived
by the Commission.
21. In the event that a Publicly Owned Utility's (POU) Security Plan has not
been adopted in time as required by this decision, the POU shall provide the
Director of the Commission's Safety and Enforcement Division with a notice
[30] days prior to the deadline with information on the nature of the delay and
an estimated date for adoption.
22. Prior to Security Plan adoption, Publicly Owned Utilities in California
shall have their plan reviewed by a third party.
23. Such third-party reviewer may be another governmental entity within the
same political subdivision, so long as the entity can demonstrate appropriate
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R.15-Q6-009 COM/CR6/avs
expertise, and is not a division of the publicly owned utility that operates as a
functional unit (i.e., a municipality could use its police department if it has the
appropriate expertise).
24. Publicly Owned Utilities shall conduct a program review of their Security
Plan and associated physical security program every five years after initial
approval of the Security Plan by their Board of Directors or City Council. Notice
of such approval action shall be provided to the Commission's Safety and
Enforcement Division withzn 30 days of Plan adoption by way of copy of signed
resolution or letter by a responsible elected- or appointed official, or utility
director.
25. Pacific Gas and Electric Company, San Diego Gas & Electric Company,
Southern California Edison, PacifiCorp, Bear Valley Electric Service, and Liberty
CalPeco shall conduct a program review of their Security Plan and associated
physzcal security program every five years after Commission review of the first
iteration of the Security Plan.
26. A summary of the program review shall be submitted to the Safety and
Enforcement Division within 30 days of review completzon.
27. In the event of a major physical security event that impacts public safety
or results in major sustained outages, all utilities shall preserve records and
evidence associated with such event and shall provide the Commission full
unfettered access to information associated with its physical security program
and the circumstances surrounding such event.
28. An Exemption Request Process shall be available to utilities whose
compliance would be clearly inappropriate or inapplicable or whose
participation would result in an undue burden and hardship.
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R.15-Q6-009 COM/CR6/avs
29. Utilities shall provide to the Director of the Safety and Enforcement
Division and Energy Division copies of 0E-417 reports submitted to the United
States Department of Energy (U.S. DOE) within two weeks of filing with
U.S. DQE.
30. Pacific Gas and Electric Company, San Diego Gas & Electric Company,
Southern California Edison, PacifiCorp, Bear Valley Electric Service, and Liberty
CalPeco (collectively, IOUs) sha11 seek recovery of costs associated with their
respective Distribution Security Programs in each IQU`s general rate case.
31. The utilities shall submit an annual report by March 31 each year
beginning 2Q20, reporting physical incidents that result in any utility insurance
claims, providing information on incident, location, impact on infrastructure and
amount of claim. The insurance claim disclosure reporting, as described in this
decision, should be included within a utility's broader annual Physical Security
Report to the Commission due every March 31, beginning in 2020.
32. As appropriate, the requirements set forth in Phase I of this proceeding
shall apply to Alameda Municipal Power, City of Anaheim Public Utilities
Department, Azusa Light and Water, City of Banning Electric Department, Biggs
Municipal Utilities, Burbank Water and Power, Cerritos Electric Utility, City and
County of San Francisco, City of Industry, Colton Public Utilities, City of Corona,
Eastside Power Authority, Glendale Water and Power, Gridley Electric Utzlity,
City of Healdsburg Electric Department, Imperial Irrigation District, Kirkwood
Meadows Public Utility District, Lathrop Irrigation District, Lassen Municipal
Utility District, Lodi Electric Utility, City of Lompoc, Los Angeles Department of
Water & Power, Merced Irrigatian District, Modesto Irrigation District, Moreno
Valley Electric Utility, City of Needles, City of Palo Alto, Pasadena Water and
Power, City of Pittsburg, Port of Oakland, Port of Stockton, Power and Water
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R.15-Q6-009 COM/CR6/avs
Resources Pooling Authority, Rancho Cucamonga Municipal Utility, Redding
Electric Utility, City of Riverside, Roseville Electric, Sacramento Municipal
Utility District, City of Shasta Lake, Shelter Cove Resort Improvement District,
Silicon Valley Power, Trinity Public Utility District, Truckee Donner Public
Utilities District, Turlock Irrigation District, City of Ukiah, City of Vernon,
Victorville Municipal Utilities Services, Anza Electric Cooperative, Plumas-Sierra
Rural Electric Caoperative, Surprise Va11ey Electrification Corporation, and
Valley Electric Association.
33. This proceeding sha11 rema�n open so that the Commission may address
the issues presented in Phase II of this proceeding.
Th�s order is effective today.
Dated January 10, 2019, at San Francisco, California.
MICHAEL PICKER
President
LIANE M. RANDOLPH
MARTHA GUZMAN ACEVES
CLIFFORD RECHTSCHAFFEN
Commissioners
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�
� _ ,
�
DATE: March 25, 2021
TO: Dan Beans, Director of REU
FROM: Levi Solada, Redding Police Lieutenant
SUBJECT: REU SB 699 Utility Seeurity Plan Independent Review
On February 11, 2021, I met with REU Program Supervisor Shawn Avery and was provided with
REU's Utility Security P1an to eonduct a third-party independent review. This independent review
is required under California State Senate Bill (SB) 699. I have raviewed the Utility Security Plan
in its entirety, conducted multiple physical inspections of several of the substations identified in
the Plan, and will offer my reeommendations.
I have b�en employed as a law enforcement officer with the City of Redding Police Department
for the past 18 years and am currently a Lieutenant in charge of the Investigations Division. My
background includes work in all areas of policing, to include Patrol, Investigations, and SWAT. I
am currently the SWAT Team Taetical Cornznander and have been a member of the SWAT team
for the last 16 years. I have completed hundreds of tiraining hours devoted speeifically to tactical
training. Throughout zr�y career, I have conducted nulnerous security and safety site survey
assesslnents on government and private facilities as well as reviewed security plans for
organizations throughout the City of Redding. These locations have included the Shasta County
Courthouse, City of Redding City Hall, private businesses, hospitals, specialized faeilities, and
residences. While conducting site survey assessments, several factors are taken into eonsideration
that inelude: overall security measures in place, ingress and egress routes, general construction,
hazardous materials, interna]lexternal security risks, crime prevention measures, target hardening,
situational awareness and future plans to improve security at these locations.
The City of Redding Utility Security Plan is a comprehensive plan which has be�n implemented
and has taken numerous steps to protect the infrastructure of the City's electric utility, specifically
related to the substations noted below. The Plan clearly identifies the goals of ensuri�lg the safety
of its facilities as the top priority for REU. There are multiple REU facilities throughout the City
to inelude a Power Control Center, a Departm�nt Operations Center, and twelve (12) distribution
substations. :Below is a list of REU's substations. Although the security requirements of SB 699
are specific to "Critical Distribution Faeilities" I noted in REU's Security Plan the intent is to
ensure all substations are treated the same as related to security. Below is a complete list of REU's
substations.
Substatian Faeilities
Air ort ll51cV Substation
Beltlule Substation
Canb �Substation
Colle e View Substation
East Reddin Substation
Eureka Wa Substatian
Moore Road Substatian
Ore on Street Substatian
Reddin Power Subs�ation
Slal hur Creek Substation
Texas S rin s Substation
Waldan Substation
�
The Utility Security Plan has identi�ed capital improvements which will enhance the existing
security measures I have outlined and will improve the resilience of a11 REU substations. The first
i�nprovement is to have additional fixed high definition cameras, including Automatic License
Plate Readers(ALPR). The ALPR technology allows law enforcement to have access to a database
of information whieh is a tool for law enforcement to help identify any threats near REU faeilities.
This is a collaborative database of information gathered from multiple ALPR systems throughout
the state and is being used by multiple law enforeement ageneies. The Redding Police Departlnent
could be notified of any potential identified threat, via an ALRP, if installed on the ingress ar
egress routes related to REU substation facilities.
Although Redding Police Department's response tilne for crimes in progress or past tense property
crimes is signifieantly faster than the national average, the addition of technology will assist law
�nforcement when responding to an incident related to one of REU's substations. This technology
would greatly assist with an investigation if any REU facility was ever a target of terrorisln,
vandalism, theft, or any other associated praperty crime. Additional high definition cameras
installed at various REU� substations would not only assist with crime prevention measures, but
would also aid in identifying other threats, including wildfires encroaching on REU facilities.
In my review of the Utility Security Plan as it relatas to the REU substations, I would recormnend
implementing the im rovements outlined in the:Plan,which are needed to enhance overall securit
of the substations.
If all of these security improvements are implemented,the overall safety of the
City's utilities will be enhanced.
To complete my review of REU's Utility Security Plan, I feel it is a detailed and comprehensive
plan. The written Plan is comprised of several areas including:
• Overview
• Background
+ P1an Development Process
+ Identi�eation of Facilities
* Risk Assessment
• Mitigation Planning
• Evaluation and Response
• Validation
• Narrative Descriptions for the Plan
• Appendices
In my opinion, REU's written Utility Security Plan has adequately provided specific details,
making this an effective security plan for the City's utilities. This Plan provides safety measures
needed for the critical infrastructure identified through SB 699 and for the citizens of Redding. In
addition, REU has clearly identified areas to iinprove its security and mitigate risk as noted in the
REU�Wil�re Mitigation Plan.
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tl''C
a
� �
� �' ��'� INT�RNAL
` � �. I TI
DATE: May 17, 2021
TO: Dan Beans, Director of Redding Electrie Utility (REU)
FROM: Jay Sumerlin, City of Redding Deputy Fire Chief
SUSJECT: REU SB 699 Utility Security Plan Validation as required by the California Public
Utilities Commission (CPUC)
On May 13th, 2021, T received a copy of the REU Utility Security Plan, including an independent
security revi�w performed by Lt. Levi Solada from the Redding Police Department. In addition, I
made a site visit to a substation facility with REU� Program Supervisar, Shawn Avery and found
that the substation security complies with the written security plan. The REU substation security
measures, as documented in the Plan, are both thorough and appropriate to mitigate criminal
activity on or near the distribution facilities.
My knowledge and experience related to emergency operations as well as criminal aetivity provide
me with the appropriate training to validate REU's Utility Security Plan. I have been employed
with th�Redding Fire Department as the Deputy Fire Chief for nearly two years.Before my current
position, I served another fire agency in Washington State for over twenty-seven years. I have
many hours of training in Emergeney Planning, Emergency Response to Terrorism, and T am a
liaison to the Fusion Center. In addition, I held the L,ocal Emergency Planning Cominittee Chair
and have been part of an FBI Joint Terrorisln workgroup in Washington State.
The REU Security plan is weIl written and comprehensive. In addition, the recommendations for
capital improvements autlined in the plan and that of the independent evaluator will enhance site
security, adding additional elements of threat detection that will aid law enforcement in protecting
the power grid. Therefore, in my review of the REU Utility Security Plan and the ind�pendent
review conducted by the Redding Police Department, T have determined that the plan and
independent review are valid under the guidelines required by the CPUC decision for Publicly
Owned Utilities.
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The Substation Security Map has been redacted due to the con�dential information in the map.
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APPENDiX E
REU TECHNOLOGY
SOLUTIONS PROGRAM
Page i of 20 Rev. 1213/19
tJverview
Through the application of technology, REU will be able to more effectively proteet and reduce
threats to the electric utility infrastructure and the customers who rely upon it. The following
technologies will greatly enhance REU's ability to minimize sources of ignition, manage
vegetation within the City's electric grid, enhance productivity of utility staff, harden systems,
more effeetively prot�ct and notify the public if an issue arises, as well as shorten the response
and recovery time in the event REU equipznent contributes to starting a wildfire.
Technology also helps to heighten situational awareness and enhances public safety response
time, allowing first responders to react in an appropriate and effective manner before, during and
after a wildfire. The Program provides funding to the Redding:Police Department (RPD) and the
City Information Technolo�,ry(IT) Departinent for services rendered to help prevent REU caused
wildfires and protect REU facilities from the threat of wildfires through aerial surveys of REU's
overhead electric lines, video monitoring of faeilities, a eolnmon communication platform, and a
G�PS based vehicle tracking platform. The memorandums of understanding (MOU�s) are
attached.
Speeifieally, this program provides for an estimated total of forty(40) cameras; a eolnmon radio
platform, including base stations, handhelds and vehicle mounted radios for REU personnel as
well as radio equipment for Redding Police and Fire command Staff; and Automatic Vehicle
Location(AVL) tracking devices on a11 Electric Utility vehicles and necessary upgrades for first
responder vehicles. The common communication and GPS vehicle traeking platforms will be
expandable and be designed to allow easy adoption by o�her City Departments at a slnall
incremental cost.
Cameras for Utility Operations Fire Detection and Miti�atian
Situational awareness is instnlmental in coinbating�res in and around our eommunity. Camera
technology is a vital element in the early detection and intrusion of wildland fires into the City of
Redding. In addition, cameras provide critical information r�lated to any REU equipment that
may be a contributory cause to a fire. The installation of cameras in areas surrounding REU's
eritical infrastructure will greatly enhance first responder's ability to identify, locate, and
mitigate fire threats.
Live feed cameras mounted throughout REU's serviee territory will assist with the early
d�teetion of fires caused by the electric system. Strategically placed cameras in the proximity of
REU's transmission lines, especially in the Tier 2 and Tier 3 fire areas, will also aid in risk
assessinents during designated Red Flag warning days or a fire weather event in whieh an
Emergency Operations Center is activated. Early assessment and detection allows REU to
quickly react and pr�vent the system from inflicting harm on the surrounding areas.
Mobile caineras will also be used in a variety of preventative ways through the use of Unmanned
Aerial Vehicles (U�AVs). This includes the identification of potential right-of-way hazards as
w�ll as the location and isolation of hot spots in REU distribution li�les using Forward Looking
Infrared Radar(FLIR) technologies.
REU Wildfire Mitigation Plan Rev Deccinber 3, 2019
APPENDIX E
REU TECHNOLOGY
SOLUTIONS PROGRAM
Page 2 of 20 Rev. 12/3119
In the event a fire is seen or reported, fixed cameras and UAVs can quicicly discover and identify
hot spots in the area, help determine the potential for the fire to spread, and give first responders
specific intelligence related to scaling fire resources up or down appropriately. In addition,
strategieally placed fixed calneras assist first respond�rs in determining the best evacuation
routes througla enhanced situational awareness. Fixed and UAV cameras allow firefighters and
first responders to more effectively manage firefighting operations. Speakers mounted on UAVs
greatly enhance the ability to communicate with first responders in the danger area and with
citizen evacuations.
HD videa streaming from the UAVs to the Department Operation Center(DOC) or command
staff on computers/cell phones wi11 allow those in control of fire operations to see a live,real-
time video feed of the fire. This will streamline firefighting capabilities and enabl� coininand
center personnel to make quick decisions based on real-tilne information, rather than using
information that has been relayed through multiple parties or having to wait until first responders
are in place. Command center personnel will be able to see the direction a fire is spreading,
providing the ability to mova resources to the most effective positions.
Implelnentation of an artificial intelligence overwatch camera and software system will assist in
the early detection of fires. Fire watch systems are specifically manufactured for early wildfire
detection and can be calibrated for any region, vegetation, and type of weather. This technology
includes a triple optical sensing unit, control and detection software that performs self-
diagnostics, and smoke detection. While this technology is recommended to be used with a
detection radius of ten (10) miles, it has proven itself capable of locating smoke plumes up to
forty(40) miles away during clear weather days. When smoke is detected by the system it alerts
users so that �rst responders can react quickly and efficiently before flames reach the tree tops.
Early detection of�re arising proximate to REU facilities using the systein allows first
responders to launch a direct attack using minimal resources and results in both physical and
monetary savings to REU.
Fire caused by REU facilities or threatening REU facilities can rapidly becoming a city-wide
tlareat to the inhabitants of the City. City-wide issues and concern can begin long before the
cause of a�re is known due to lack of certainty. By determining the cause, or origin, of a fire
quickly, we can not only save life and properties, we can mitigate the risk of uncertainty. :In this
regard, early detection of fire caused by REU faciliti�s or threatening REU facilities protects the
City as a whole.
Aerial Ima�erv
The city-wide aerial orthophotography is a core data set for the GIS Division. Aerial imagery or
orthophotography provides the picture from which lnany GIS data layers are created and
maintained. For example, our parcels, roads, water system, wastewater system, and storm drain
system GIS layers are all created and maintained using high-resolution orthophotography. Also,
high-resolution imagery is a powerful visual tool when represented on maps and exhibits. Tt is
important that the imagery be kept up-to-date. The most recent a�rial imagery was flown prior to
the Carr fire, and is therefore not a true representation of our community's current landscape.
REU Wildfire 1Vlitigation Plan Rev Decelnber 3, 2019
APPENDIX E
REU TECHNOLOGY
SOLUTIONS PROGRAM
Page 3 of 20 Rev. 12f3/19
New imagery would allow�re crews to be able to identify current overgrown areas proximate to
R.EU facilities, as well as those areas at a higher risk of fires. Ensuring the imagery is kept up to
date on a more frequent basis will play a critical role in ensuring fire crews are able to maintain a
clearer/safer landscape around REU facilities as vegetation regrows. N�ewer imagery would allow
for accurate GIS data, which in turn, would further enhance the City's Fire Department in their
�re mitigation efforts to enhance wildfire buffers around REU facilities. This imagery will be
performed every two years.
Ci�-Wide Communications Platform
Immediate and reliable communication is vital during an emergency such as a wildfre, or major
storm event. The current City of Redding radio systems have reached tl�eir end of useful life and
are requiring replacement. RPD is currently in the process of upgrading their existing radio
system and REU is proposing to expand upon this project to include additional features that will
meet Redding Electric Utility's need to monitor and react to wildfire threat to REU facilities or
to protect the City from wildfire threat posed by REU facilities while also creating a unified
platform across City Departments. By implementing a unified stationary and mobile
communication platfoi-m, City of Redding personnel will have the ability to communicate across
Departm�nts during emergency situations quicicly and ef�ciently. This platform will provide
immediate cannection to all parties, free of cross-channel interference, aLlowing each
D�partment to work simultaneously and in support of one another. In addition to purchasing the
communications platfonn, :REU will provide radios for Electric Utility employees and Redding
Police and Fire coinlnand staff to ensure reliable communication between first responders and
REU to ensure the preservation of life and property. *Initial costs associated with the
cominunications platform will be paid by REU. The Radding Police Department will be
responsible for a partial repayment for handheld and vehicle radios through an interdepartmental
l�ase process.
This radio system will allow first respoi�ders to immediately report downed elactric lines to REU
or report a fire that has been started due to a downed 1ine. This will lead to faster response times
and better fire management. Direct radio communication between Redding Fire Department
personnel to Police personnel will provide safe direction to high risk areas during evacuations as
well as allow first responders to r�quest specific power shutoffs from REU's DOC during an
emergency.
Automatic Vehicle Location (AVL)
AVL will assist each Department with the identification and tracking of first responder and
�mergency vehicles. During a wildfire event, it is critical for the Department Operations Center
(DOC) to be able to determine the location of each vehicle so that resources can be dispatched
and/or redirected to REU facilities in the inost effective manner, and to identify where a vehicle
is located so assistance may be provided if an employee is in danger. AVL aids in the
identification of einployee location during emergencies and allows dispatchers to warn personilel
who are in the vicinity of an at-risk area.
REU Wildfire Mitigation Plan Rev Decelnber 3, 2019
APPENDIX E
REU TECHNOLOGY
SOLUTIONS PROGRAM
Page 4 of 20 Rev. 12/3/19
AVL,will allow REU to track the progress of employees while patrolling equipinent during a
Red Flag outage. By doing so, REU can ensure that outages are handled quickly and efficiently,
and that employees are not at risk. If an emergency situation is identified, AVL will provide
REU with the ability to quickly report a vehicle's location and allow dispatchers to send�rst
responders directly to the vehicle and employee(s).
REU Wildfire 1Vlitigation Plan Rev Decelnber 3, 2019
APPENDIX E
REU TECHNOLOGY
SOLUTIONS PROGRAM
Page 5 of 20 Rev. 12/3/19
REU Wildfire Technology Matrix
Caineras for Aerial Citywide Automatic
Detection& Imagery Communications Vehicle Loeation
Mitigation Platform (AVL)
Vegetation x x
Mana ement
Enhanced x x x
Inspections
Situational x x x x
Awareness
Operational x x x
Practices
System Hardening x x x x
Public Safety& x x x
Notification
Reclosing& x x x
Deenergization
Wildfire Response x x x
&Recovery
REU T�chnology S�rategies Matrix
Cameras for Aerial Citywide Automatic
Detection& Imagery Communications Vehicle Location
Mitigation Platform (AVL)
Wildfire x x x x
Prevcntion&
Improved
Response
Technology x x x x
Solutions
Distribution 1 Q- x x x
year Capital
Improvements
REU Emergency x x x x
Operations
Budgetary Cost Estimate
Item# Item I)escription Total Cost
1 Caineras for Utility Operation,Fire Detection and $2,989,000
Mitigation
2 Aeriallmagery $SO,Q00
3 City-Wide Communication Platform $8,820,000
4 Automatic Vehicle Location(AVL) $60,000
Tatal $11,919,000
REU Wildfire Mitigation Plan Rev Decelnber 3, 2019
APPENDIX B
REU TECHNOLOGY
SOLUTIONS PROGRAM
Page;6 of 20 R�v. 12/3119
CITY t3F REDDING
MEMORANDUM OF UNDERSTANDING
RPD—WMP - 1
THIS 1VIEMORANDUlYI OF UNDERSTANDING (1VIOU) is made at Redding, California, by
and between Redding Electric Utility (REU), an enterprise business unit of the City of Redding
(City) a municipal corporation, and Redding Police Departl�ent (RPD), a general fund business
unit of the City, for the purpose of wildfire prevention and improved technology.
WHEREAS, SB 901 was adopted by Governor Brown on September 21, 2018; and REU does not
have sufficient personnel to perfarm the services required herein thereby necessitating this 1V10U
for RPD services.
WHEREAS, SB 901 requires the REU to draft and implement a Wildfire Mitigation Plan for the
purpose of preventing the start of wildfires resulting from utility operations as well as to expand
technolo�ry in order to reduce the catastrophic impacts which may be caused by or inflicted upon
REU facilities or operations.
WHEREAS, the City Council approved a program providing for RPD to support REU in
implementation of a Wildfire Mitigation Plan as more fully defined herein, and authorized the Ciry
Manager to execute this MOU between the parties.
NOW, TIIEREFORE, the Parties covenant and agree, for good consideration hereby
acknowledged, as follows:
SECTION 1. RPD SERVICES
Subject to the terms and conditians set forth in this MOU, RPD shall provide to REU the
services described in Exhibit A - REU� Teehnology Solutions Program, attached and
incorporated herein. RPD shall provide the services at the tiine, place, and in the manner
specified in Exhibit A.
SECTItJN 2. COMPENSATION AND REIMBURSEMENT OF COSTS
A. REU shall reimburse RPD for services rendered pursuant to this MOU� through the
City Budgeting process and as described in E�ibit B. Exhibit B is attached and
incorporated herein, in a total amaunt not to exceed one million�ve hundred ninety-
nine thousand dollars ($1,189,000) for the purchase and implementation of
technology, as weil as the training af staff inembers. This sum is further limited in
each technology category as shown in Exhibit B.
Consulting and Professional Services Agreement Pa�ge 1
Rev. 11/19/2019
APPENDIX E
REU TECHNOLOGY
SQLUTIONS PROGRAM
Page 7 of 20 Rev. 12/3/19
SECTION 3. T:ERM AN:D TER.IVI:INATTON
A. RPD shall commence work on or about the date of this agreement and continue or be
terminated with mutual agreement of existing or modified terms by REU and RPD.
B. RPD hereby acknowledges and agrees that the obligation of REU to pay under this
MOU is contingent upon the availability of City's funds which are appropriated or
alloeated by the City Council. Should the funding for the project aild/or work set
forth herein not be appropriated or allocated by the City Council, this NIOU shall
tenninate when the funding is exhausted.
C. In the event that City Council terminates the program,RPD shall provide to REU any
and a11 finished and unfinished reports,charts or other work product prepared by:RPD
pursuant to this MOU.
D. In the �vent the City Council terminates the program, REU shall pay RPD the
reasanable value of services rendered by RPD pursuant to this MOU. R.PD shall, not
later than thirty (30) calendar days after termination of this MOU, furnish to REU
sueh financial infonnation as in the judglnent of the REU's representative is
necessary to determine the reasonable value of the services rendered by RPD.
SECTION 4. MISCELLANEOUS TERMS AND CONDITIONS OF MQU
A. No portion af the work or serviees to be performed under this MOU shall ba assigned,
transferred, conveyed or subcontracted without prior written approval of REU, the
City Manager or the City Council.
B. RPD, at such times and in such form as REU may requira, shall furnish REU with
such periodic reports as it may request pertaining to the work or services undertalcen
pursuant to this MOU.
C. RPD shall maintain accounts and r�eords,including personnel,property and financial
reeords, adequate to identify and account for all costs pertaining to this MOU� and
sueh other records as may be d�emed naeessary by REU to assure praper accounting
for a11 project funds. These records shall be made available for audit purposes to state
and federal authoritiies, or any authorized representative of City. RPD shall retain
such records for three (3) years after the expiration of this MOU, unless prior
permission to des�roy them is granted by REU.
SECTION 5. MOU INTERPRETATION AMENDMENT AND WAIVER
A. This document, includin� all exhibits, contains the entire agreement between the
parties and supersedes whatever oral or written understanding each may have had
prior to the execution of this MOU. This MOU shall not be alterad, amended or
Consulting and Professional Services Agreement Pa�ge 2
Rev. 11/19/2019
APPENDIX E
REU TECHNOLOGY
SOLUTIONS PROGI�AM
Page 8 of 20 Rev. 12/3119
modi�ed except by a writing signed by REU and RPD and duly authorized by the
City Manager. No verbal agreement or conversatian with any offieial, officer, agent
or employee of City, either befare, during or after the axecution of this MOU, shall
affect or modify any of the terms or conditions contained in this 1VIOU.
B. No covenant or condition to be performed by RPD under this MOU can be waived
except by the written consent of REU. Forbearance or indulgence by REU in any
regard whatsoever sha11 not constitute a waiver of the eovenant or condition in
question.
C. In the event af a conflict between the term and conditions of the body of this MOU
and those of any exhibit or attachment hereto, the terms and conditions set forth in
the body of this MOU proper sha11 prevail. In the event of a conflict between th�
terms and conditions of any two or more exhibits or attachments hereto, those
prepared by REU shall prevail over those prepared by RPD.
SECTION 6. SUR�IVAL
The provisions set forth in Sectians 3 through 5, inclusive, of this MOU shall survive
tennination of the MOU.
SECTION '7. COMPLIANCE WITH LAWS
RPD shaIl comply with all applicable laws, ordinances and codes of federal, state and local
governments.
SECTIQN $. REPRESENTATIVES
A. REU's representative for this MOU is the Redding Eleetric Director Daniel Beans,
telephone nulnber (530) 339-7350. A11 of RPD's questions pertaining to this MOU
shall be referred to the above-nam�d person, or to the representative's designee.
B. RPD's representative for this MOU is Redding Polic� Chief Williain Sehueller,
telephone number (530) 225-4284.
C. The representatives set forth herein shall have authority to give all notices required
herein.
SECTION 9. DATE UF MOU
The date of this MQU sha11 be the date it is signed by REU.
Consulting and Professional Services Agreement Pa�ge 3
Rev. 11/19/2019
APPENDIX E
REU TECIINOLOGY
SOLUTIONS PROGRAM
Page 9 of 20 Rev. 1213/19
IN WITNESS WHEREOF, REU and RPD have executed this MOU an the days and year set
forth below:
CITY OF REDDING,
A Division of a Municipal Carporation
Dated: ,2019
By: Daniel Beans, Electric Utility Director
ATTEST: APPROVED AS TO FORM:
SARRY E. DeWALT
City Attorney
PAMELA MIZE, City Clerk By:
Redding Police Department
Dated: , 2Q19
By: William Schueller, Chief of Police
Consulting and Professional Services Agreement Pa�ge 4
Rev. 11/19/2019
APPENDIX E
R�U TECHNOLOGY
SOLUTIONS PROGRAM
EXhlbit A Page 10 of 20 Rev. 12/3/19
REU Technalagy Solutions Program
1. Introduction
A. Puipose
The purpose of the Redding Electric Utility (REU) Technology Solutions Program is ta
establish a framework far the elec�ric utility to conduct ai� effective, coordinatcd program
to prcvent catastrophic impacts ta its infrastructure from wildfiree This prograin is a
significant component of the Redding Electric Utility Wildfire Mitigation Plan required
by SB901. The Prograzn aims to prevent the start of wildfires froin utility operations as
well as provide faster response in the event of a wildfire either caused by or threatening its
electric utility ass�ts located in and around the City of R�dding.
B. Goais
• Prevent �lec�ric utility-caused wild�ires.
• Reduce�he time for the Redding Police D�pai-tment(RPD)ta report,respond to, and
engage in emergencies that threaten grid infrastructure and oth�r REU facilities,
• Increase technology use and reliability in order to promota interdepartmental
coordination.
C. Qbjectives
The Prograin's primary objectives are to:
• Tdentify hazards that pose a potential threat of damaging wildfires that may
reasonably be likely to affeet REU facilities.
• Prioritize interdepartmental communication through radios.
• Quiel�y identify possible fire risks and choreograph proper response routes.
• Decrease recovery time after a fire oecurs.
• Increase accuiacy of fire investigation results.
• Utilize cameras to identify possible tlareats that are naturally occurring or human caused.
• Track progress and location of employees to ensure the safety and effectiveness of
positioning.
2. StrategylScope of Work
A. REU will coordinate with RPD to fund the follawing technology:
• Unmanned Aerial Vehicle (UAV)
• Cameras for Surveillance,Fire Detection, and Inv�stigation
Page S
APPENDIX E
REU TECHNOLOGY
SOLUTIONS PROGRAM
E�Xhlbl� A Page 11 of 20 Rev. 1213/19
REU Technology Solutions Program
B, Redding Poliee Department �o proeure technology deemed neeessary as well as
provide staff and requisite training to operate the follawing technology:
• UAV units: RPD will assist REU in the aerial patrol of overhead lines using U�AV�s
equipped with Forward Looking Infrarcd Radar(FLIR). This s�rvice will be
provided on an as i7eeded basis but at a ininimum of once ycarly as required by
California Public Utilities Commission General Order 165. This process aids in
ensuring the stability of REU's overhead lines and assists in the location and
mitigation of potential fire hazard risks.
• UAV units: RPD will assist RFD in the monitoring of fires using UAVs equipped
with FLIR technology. This serviee will be provided on an as needed basis.
• Cameras for Surveillance,Fire Detection, and Investi�ation: RPD will assist REU in
the detection as wall as inves�igation of fire origination and cause of ig�ition tl�rough
tl�e use of fixed andlor 1�Zobzle camaras.
• Radio System: RPD will report all Utility related fire hazards to REU personnel
tl�raugh the unified communication platform.
Page 2
APPENDIX E
REU TECHNOLOGY
SOLUTIONS PROGRAM
�xhlbi� B Page 12 of 19 Rev. 1213119
REU Technology Solutions Program
st sti tes
l. UAVs
• Four(4)UAVs equipped with FLIR ca�abilities
• Two (2) UAVs without FLIR ca abilines
• One (1)Insi�ht RT Systeln with��oad Case
• Yearly Inspect�on of Power Lines
o Total cost ls not to exceed$230,000
2. Cameras
• Forty (40) fixed cameras
• Intelligence Led Policing (ILP)
• 3D Laser Scanner and Equipment
• Added equipment and warranties
o Total cost ls not to exceed$959,000
Page 3
APPENDIX E
REU TEGHNOLOGY
SOLUTIONS PROGRAM
Pa�e 13 of 20 Rev. 1213/19
CITY OF REDDING
MEMORANDUM OF UNDERSTANDING
IT-WMP-1
THIS 1VIEMORANDUlYI OF UNDERSTANDING (MOU) is made at Redding, California, by
and between Redding Electric Utility (REU}, an enterprise business unit of the City of Redding
(City) a municipal corporation, and Information Technology Department (IT), a general fund
business unit of the City, for the purpose of wildfire prevention and 'zmproved technology.
WHEREAS, SB 901 was adopted by Governor Brown on September 21, 2018; and REU�does not
have suffcient personnel to perform the services required herein thereby n�cessitating this MOU
for IT services.
WHEREAS, SB 901 requires the REU to draft and implement a Wildfire Mitigation Plan for the
purpose of preventing the start of wildfires resulting from utility oparations as well as to undertake
vegetation management efforts to reduce the catastrophic impacts which may be caused by REU
facilities or operations.
WHEREAS, the City Couneil approved a program providing for IT to support REU in
implementation of a Wildfire Mitigation Plan as more fu11�defined herein, and authorized the City
Manager ta �xecute this MOU between the parties.
NOW, THEREFORE, the Parties covenant and a�;ree, for good consideration hereby
acknowledged, as follows:
SECTICIN l. IT SERVICES
Subject to the terms and conditions set forth in this 1VIOU, IT shall provide to REU the
services deseribed in Exhibit A - REU Teehnology Solutions Program, attached and
incorporated herein. TT shall provide the services at the time, place, and in the manner
speci�ed in Exhibit A.
SECTION 2. COMPENSATION AND REIMBURSEMENT OF COSTS
A. REU shall reimburse IT for services rendered pursuant to this MOU thrau�h the City
Budgeting process and as described in Exhibit B. Exhibit B is attached and incorporated
herein, in a total amount not to exceed eight million eight hundred eighty-one thousand
doIlars ($10,'730,000) for the purchase and implementation of technology, as well as
the training of staff inembers. This sum is further limited in each technolo�,ry category
as shown in Exhibit B.
Consulting and Professional Services Agreement Pa�ge 1
Rev. 11/19/2019
APPENDIX E
REU TECHNOLOGY
SOLUTIONS PROGRAM
Page 14 of 20 Rev. 12/3/19
SECTION 3. T:ERM AN:D TER.IVI:INATTON
A. IT shall commence work on or about the date of this agreement and continue or be
terminated with mutual agreement of�xisting or modified terms by REU and IT.
B. IT hereby acknowledges and agrees that the obligation of REU to pay under this
MOU is contingent upon the availability of City's funds which are appropriated or
allocated by the City Council. Should the funding for the project and/or work set
forth herein not be appropriated or allocated by the City Council, this 1VIOU shall
tenninate when the funding is exhausted.
C. In the event that City Council t�rminates the program, IT shall provide to REU any
and all finished and un�nished reports, charts or other work product prepared by TT
pursuant to this MOU.
D. In the event the City Council terminates the program, REU shall pay IT the
reasonable value of services rendered by TT pursuant to this MOU. TT shall, not later
than thirty (30) calendar days after termi�lation of this MOU, funush to REU such
financial information as in the judgment of the REU's representative is necessary to
determine the reasonab�e value of the services rendered by IT.
SECTION 4. MISCELLANEQUS TERMS AND CONDITIONS OF MOU
A. No portion of the work or services to be performed undar this MOU shall ba assigned,
transferred, conveyed or subcontracted without prior written approval of REU, the
City Manager or the City Council.
B. IT, at such times and in such form as REU may require, shall furnish REU with such
periodic reports as it may request pertaining to the work or services undertaken
pursuant to this MOU.
C. IT shall maintain accounts and records, including personnel, praperty and financial
records, adequate to identify and account for all costs pertaining to this MOU� and
such other records as may be d�emed necessary by REU to assure proper accounting
for a11 project funds. These records shall be made available for audit purposes to state
and federal authorities, or any authorized representative of City. IT shall retain sueh
records far three (3} years after the expiration of this MOU, unless prior permission
to destroy them is granted by REU.
SECTION 5. MOU INTERPRETATION AMENDMENT AND WAIVER
A. This document, includin� all exhibits, contains the entire agreement between the
parties and supersedes whatever oral or written understanding each may have had
prior to the execution of this Mt�U. This MOU shall not be alterad, amended or
Consulting and Professional Services Agreement Pa�ge 2
Rev. 11/19/2019
APPENDIX E
REU TECHNOLOGY
SOLUTIONS PROGRAM
Page 15 of 20 Rev. 12/3/19
modified except by a writing signed by REU and IT and duly authorized by tihe City
Manager. Na verbal agreement or conversation with any official, offieer, agent or
employee of City, ei�her before, during or after tha execution of this MOU, shall
affect or modify any of the terms or conditions contained in this MOU.
B. No covenant or condition to be performed by IT under this MOU can be waived
except by the written consent of REU. Forbearance or indulgence by REU in any
regard whatsoever shall not constitute a waiver of the eovenant or condition in
question.
C. In the event of a conflict between the term and conditions of the body of this MOU
and those of any exhibit or attachment hereto, the terms and conditions set forth in
the body of this MOU proper sha11 prevail. In the event of a conflict between th�
terms and canditions of any two or more exhibits or attachinents hereto, those
prepared by REU shall prevail over those prepared by IT.
SECTION 6. SURVIVAL
The provisions set forth in Sectians 3 through 5, inclusive, of this MOU shall survive
tennination of the MOU.
SECTION '7. COMPLIANCE WITFI LAWS
IT shall comply with all applieable laws, ordinances and codes of federal, state and local.
governments.
SECTI N 8. E ESENTATIVES
A. REU's representative for this MOU is the Redding Eleetric Direetor Daniel Beans,
telephone number(530)339-'735Q. All of IT's questions pertaining to this MOU shall
be referred to the above-named person, or to the representative's designee.
D. IT's representative for this MOU is Redding Information Technolo�ry Director
Anthony Van Boekel, telephone number (530) 225-4070.
E. The representatives set forth herein shall have authority to give all notices required
herein.
SECTI N 9. ATE F U
The date of this MOU sha11 be the date it is signed by REU.
Consulting and Professional Services Agreement Pa�ge 3
Rev. 11/19/2019
APPENDiX E
REU TECNNOLOGY
SOLUTIONS PROGRAM
Page 16 of 20 Rev. 12/3/19
IN WITNESS WHEREOF, REU and IT have executed this NIOU on the days and year set forth
below:
CITY F E ING,
A Division of a 1Vlunicipal Corporation
Dated: , 2019
By: Daniei Beans, Electric Utility Director
ATTEST: APPROVED AS TO FORM:
BARRY E. DeWALT
City Attorney
PAMELA MIZE, City Clerk Sy:
Information Technology Department
Dated: , 2019
By: Anthony Van Soekei, Information
Technalogy Director
Consulting and Professional Services Agreement Pa�ge 4
Rev. 11/19/2019
APPENDIX E
REU TECHNOLOGY
EXhlbit A SOLUTIONS PRQGRAM
Pag�;17 of 20 Rev. 12/3/19
REU Technalagy Solutions Program
1. Introduction
A. Puipose
The purpose of the Redding Electric Utility (REU) Technology Solutions Program is ta
establish a framework far the elec�ric utility to conduct ai� effective, coordinatcd program
to prcvent catastrophic impacts ta its infrastructure from wildfiree This prograin is a
significant component of the Redding Electric Utility Wildfire Mitigation Plan required
by SB901. The Prograzn aims to prevent the start of wildfires froin utility operations as
well as provide faster response in the event of a wildfire either caused by or threatening its
electric utility ass�ts located in and around the City of R�dding.
B. Goais
• Prevent �lec�ric utility-caused wild�ires.
• Reduce the time for first responders to report,respond to, and engage in emergencies
that threaten grid infrastructur� and other REU facilities.
• Increase technology use and reliability in order to promote interdepartmental
coardination.
C. Qbjectives
The Prograin's primary objectives are to:
• Tdentify hazards that pose a potential threat of damaging wildfires that may
reasonably be likely to affect REU facilities.
• Prioritize interdepartmental communication through radios.
• Quiel�y identify possible fire risks and choreograph proper response routes.
• Decrease recovery time after a fire occurs.
• Increase accuiacy af fire investigation results,
• Utilize caineras to identify possible th.reats that are naturally occurru�g or huinaia caused.
• Traek progress and location of employees to ensure the safety and effectiveness of
positioning.
2. StrategylScope of Work
A. REU wiil coordinate with GOR Information Technology (IT) Department to
fund�he purchase and maintenance of the following technology:
• Fixed and Mobile Communication Platforrn
• Automatic Vehiele Location (AVL)
• IQ FireWatch
• AerialImagery
Page 1
APPElVI)IX E
RBU TECHNOLOGY
SOLUTIONS PRC�GRAM
E�Xhlbl� A Page 18 of 20 Rev. 12/3/19
REU Technology Solutions Program
B, City af Redding IT Department to proeure and implement tecl�nology deemed
necessary as well as p�ovide staff and requisite training to operate the following
technology:
• Radio System: The City IT Departmcnt will desigi�,purchase, and implement the
infrastructure and equipmcnt neccssary to crcate a stable radio system based within
City Limits. This system willl7ave the capacity to expand to all City Divisions that
express a need for radio use.
• Radios: The City IT Department will determine the appropriate desi�n and
funetionality of radios and order the amonnt necessary to outfit REU, RPD, and RFD.
• AVL: The City IT Department will design, unplement, and maintain�he necessary
programs and technology to expand AVL services to all vehicles in REU.
• IQ FireWateh: Tlae City IT Department will purehase, implement, and maintain the
technolagy and equipinent required to utilize the IQ FireWatch system.
• Aerial In�agery: The City IT Department will aid in the city-wide aerial
orthophotography every two (2) years and assist in its inclusion in the City's GIS
maps.
Page 2
APP�NDIX E
REU TECHNOLOGY
SOLUTIONS PROGRANI
�Xhl�i� B Page 19 of 20 Rev. 1213/19
REU Technology Solutions Program
st sti tes
1. Fixed and Mobile Cammunieation Platform
• Master Site Controller
• Two RF sites
• Bacl�haul Network
• SHASCOM Console site
• Subscribers (Radios) for RFD, RPD, REU and the E(�C
• External Serviees
• Radio Management
• Key Management Facilities
• Technical Training
• Mobile Command Center Unit
o Total cost is not to exeeed$$,820,000
2. Automatic Vehiele Location(AVL)
• AVL coverage for all vehicles in REU
o Total cost is not to exceed$60,OQ0
3. IQ FireWatch
• Triple Optical sensing unit
• Panitilt with weather housing
• Switchbox and cabling to head unit
• Control unit with remote control and Watchdog function
• Ethernet switch
• Powar supply with urge protection and EMI filter
• Control and detection software including self-diagnostics
• Detection units
• Construction of additional viewing towers
• Integration/Conn�etion to Public ServiceslEmergency Responders (Fire and Forestry
Service)
• Training and calibration labor
• Permitting fees
o Total cost is not to exceed$1,800,000
4. AerialImagery
• Provides orthophotography to the GIS division for mapping
• High-resolution imagery
o Total cost is not ta exceed$50,000 every two (2) years
Page 3
APPENDIX E
REU TECHNOLOGY
SOLUTIONS PROGRAM
Page 20 of 20 Rev. 1213119
TECHNOLQGY TOTAL CQST GENERAL REU COST
����»�»�»�»�»�»�»�»�»�»�»�»���,»�»�»�����
FUNQ COST
�1n�m���ied��r���►��e�i�le� .
.
uav�(Matir��e2io) � $ Z�s,000� � S s�s,000��
UAV(Mavic 2 Dual) $ 15,000 $ 15,000
Annual ongoing maintenance and training $ 2Q,000 $ 20,000
Insight RT System wjRoad Case $ 15,000 $ 15,000
Yearly Power Line Inspectian $ 5,OQ0 $ 5,Q00
*RPD witl provide assitance to REU and RFD $ 230,000 $ 230,000
��� � � ����� ��� .��� .�����.
C��aii�ras•.
, .... .. . . . ,„. ,. . . :�.. .. . ..: . . .. . . ., . � .,.
Fixed Cameras(4Q)with Live Feed $ 500,000 $ 800,000
Laser Scanner $ $5,500 $ 85,500
Scanner Equipment and Warranties $ 27,500 $ 27,500
Fuji File Mirrorless Camera Forensic Bundle $ 5,000 $ 5,000
Ultralight A�S Complete Turbo Kit $ 6,000 $ 6,000
Intelligence Led Policing $ 35,000 $ 35,000
IQ FireWatch $ 1,800,Q00 $ 1,80Q,000
*For use by REU, RFD, and RPD $ 2,759,000 $ 2,759,000
;� ri�l m'
� . I a � . . ...... .....:... .:.... ::::::::::: .,;. ...
m � .r1�- ,
Orthophotagraphy�every two years � $ 50,000 �� �$ � SQ,000
_ __ _
.. .. :<::<::<:.:... �. .. ... .
F��c�d��d Mi�b�le+��n�►�n.unr��t�a�t'P.1at�`�arm:: :
�., ,. ... . . ,. . . ..... ...
. ... ., .
Master Site Controller $ 8,220,000 $ 3,407,000 $ 4,813,000
-Two RF Sites
- IP Based Backhaul Netwark
-SHASCOM Cansole Site
-Subscribers(Radios)for RFD, RPD, REU,and EOC
-External Services
-Radio Management
-Key Management Facilities
-Technical Training
-Contingency Funding
-Backup Subcribers for Major Events(20)
Mobile Command Center Unit $ 550,000 $ 550,000
-Maintenanee Performed by IT $ 50,000 $ 50,000
*Subscribers provided ta REtI, RFD, and RPD $ 8,820,000 $ 3,407,000 $ 5,413,000
c� y; ,... .� .. .. ti n. . .;.. .. .:. :........:.,. ..:,:.::,. : ,.,,.,.,:
��fi .���G�fek�.�1�.i.i��� �r ��UL�...:��
.: .. . . . . ..
.. . . . .:
Additional module to ESRI Contract $ 7,000 $ 7,000
Professional Services for Installation $ 20,000 $ 20,000
Computer Hardware/Storage $ 23,000 $ 23,Q00
Contingency Funding $ 10,OQ0 $ 10,000
*lnstalted on REU, RFD, and RPD vehicles $ 60,000 $ 60,000
7��I��.J ' .,.,,� �:�,'��.�yQ�� � ', �r�d�iQ�� :� �x��.����� ���.
Ongoing costs for af1 technafogies of approximatePy$120,000 wi!l be primarily funded by the City's 1T
Department.Staff anticipates this to be partially offset by reduced maintenance due to the replacement of
aging infrastructure.
This Page Intentionally Left Blanlc
The list of REU's Critical Loads and Alternate Circuits has been redacted due to the
confidential informatian cantained in the document.
This Page Tntentionally Left Blanlc
This Page Intentionally Left Blanlc
SOP-21 Physical Security Plan for Low Impact BCS has been redacted due to the
con�dential information contained in the procedure.
This Page Tntentionally Left Blanlc
This Page Intentionally Left Blanlc
SOP-215 Electronic Access Con�rol for Low Impact BCS has been redacted due to the
eonfidential information contained in the procedure.
This Page Tntentionally Left Blanlc
This e Int tionally Le#t BI k
The Fixed Camera Loeation Map h e a te e to�he confidential i nf o ati on
ontai ne in the map
This Page Tntentionally Left Blanlc
This e Int tionally Le#t BI k
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��+�.T���.a Dl���+. D(�Ce111�1eT�l�Zd�l F�Q�: Z'OTl��i111 BQ�IC�Iy
ITEI�I NO. 4.3(a) Information TechnQlogY
l�irectar
***AFPROVED BY***
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tvanbaekel cityofreddin .or bti in cityofreddin .ar
SUBJECT: 4.3(a)--Aceess Cc�ntrol Sole-Source
Reevtnmendati+�n
Apprave sole-source procurement of the AvigilQn Access Control Manager from various
resellers/installers; to become the City of Redding�wide solution for any current aud futur�
physical acc�ss carztrol system needs.
F€scal Impact
There is no fiscal i�npact asscaciated with the approval of this s�le source request. The current
planned installations in and around City Hall and other City�f Redding (City) facilities has been
apprcaVed ir�the Fiscal Year 2021�-23 Biennial Budget:
Alter�autive Action
The City Council (Council) cauld c�ioose to not authorize the sa�e-source procurement c�f the
Avigiian Access Control Ivlanager (ACM) as the citywide access cantrol solution and provide
alternative directi�n to staff;
�ackg�°��va�Ana�ysas
Access contrQl is the mechanism that contrals key card access and provides secure door
management for employees: Cunently, the City of R�dding(City)uses an array of access control
systems at its various wc�rk locations. As the systerns begin ta fail, supporting eaeh disparate
system is difficult as current Information Technolagy Departrnent (IT) staff does not passess the
technical expertise or knawledge each system requires.
F'�clk�t IPg,��
Report to Reddin,g Czty Council �ecember 15,2021
Re: 4.3(a)__Access ContrQl S�rle-Sdurce Page 2
At the City Gc�uncil meeting an March l, 2021, the Council apprc�ved Sole-Source Purchases
related to TransmissiQn Owne�/Transmission Operator (T01TOP) Cflmpliance and Uperations.
Avigiian ACM was selected as an upgrade to the access contral system at the Redding Power
I'lant that was xequired as a result of the TOP registration. Since Aviligon ACM was selected as
the new acce�s controi system at the Redding Power Plant, the gaal is to have that same systern
implemented city-r�vide, which will streamline the management and maintenance of the system.
Some City facilities are currently facing access control system failure, and c►ther facilities have
the need for the installation for an access control system, IT would like ta standardize ta one
platfarm that will accommodate the variaus access badge needs acrass the City facilities.
Avigilon ACM pro�vides a system that wi11 allow the City ta have layered internal sys�em suppart
and a knowledge base vvith a centralizecl administration for any network connected City facility;
that is scalable f�r up to 2048 badge readers and up ta SOO,OflO identities which makes it ideal for
the City's current and fitture needs. Installation of the system will be done through a bid process.
Council Privrrty/Crty Manager Goals
• This agenda item is a routin:e operational item.
F"�+�k�t Pg.86