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Home My WebLink About _ 4.5(c)--Make a Finding to Sole-Source AMAG Technologies Physical Access Control Systems GI �" Y C� F � � �- ' � ° � � i � CITY OF REDDING �� REPORT TO THE CITY COUNCIL MEETING DATE: August 19, 2025 FROM: Nick Zettel, Director of ITEM NO. 4.5(c) Redding Electric Utility ***APPROVED BY*** . � �k ct c �rcctor�i4' c in, u-ic[Jt'riitv �l��l2t)�5 t�s�a a �, ss � eF 8,�14l202� nzettel@cityofredding.org btippin@cityofredding.org SUBJECT: 4.5(c)--Make a Finding to Sole Source AMAG Technologies Physical Access Control S stems Recommendation Approve the sole-source procurement of hardware, software, and licenses, in an amount not to exceed $250,000, for upgrading the physical access control systems at City of Redding Electric Utility substations and find that the name AMAG Technologies in the project specifications for Public Works projects, as pursuant to Public Contract Code Section 3400(c)(2), to match existing systems already in use by the City of Redding. Fiscal Impact The estimated cost of AMAG Technologies' equipment is $250,000. This project is a continuation of work that was previously approved and funded in the Fiscal Year 2023-25 biennial budget cycle. As such, the necessary funding remains available, and no additional appropriations are being requested at this time. AZteNnative Action The City Council (Council) may choose not to make a �nding to sole-source the equipment for the AMAG Technologies access control system for Redding Electric Utility (REU) substations and provide alternative direction to staff. Background/Analysis Physical access control systems regulate secure entry to sensitive sites using card-based credentialing and centralized alarm monitoring. REU's existing access system requires updating for security purposes. Report to Redding City Council August 14,2025 Re: 4.5(c)--Make a Finding to Sole-Source AMAG Technologies Physical Access Control Systems Page 2 To address this need, REU evaluated several access control platforms and selected AMAG Technologies based on its proven ability to meet the North American Electric Reliability Corporation (NERC)requixements for medium-impact facilities. AMAG systems are currently in use at REU's Power Control Center and Power Plant, where they have been successfully implemented without incident. The platform has demonstrated robust performance, compatibility with utility operations, and strong vendor support. Based on these factors, staff recommends standardizing on AMAG Technologies for a11 REU substations to ensure consistent system architecture, security compliance, and ease of maintenance. Standardizing on a specific inanufacturer requires Council to make a sole-source finding under California Public Contract Code (PCC) Section 3400(c)(2), which allows naming a particular brand in bid specifications when necessary to ensure compatibility with existing systems. This approach reduces integration complexity, streamlines technical support, and lowers long-term operational costs. The Council previously approved AMAG-related procurements, including: • On December 21, 2021, the Council approved the sole-source procurement of the Avigilon system; however, subsequent evaluations determined it did not meet NERC standards; and • On September 6, 2022, the Council authorized procurement of a new access control system, leading to the selection of AMAG Technologies for medium-impact facilities. If approved, AMAG Technologies equipment will be included in Public Works bid specifications for substation security upgrades. Staff will begin with a pilot installation at one substation and proceed with systemwide implementation pending successful results. EnviNonmental Review This activity is not a project as de�ined by the California Environmental Quality Act, and no further action is required. Council Pr�iority/City Manager Goals � Government of the 21st 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 - 12_21_2021 Access Control Sole-Source(Avigilon) Previous Staff Report - 09_06_2022 Transmission Owner and Transmission Operator REU's Utility Security Plan .,,�� .�0":.' '� :, ��;�� . CITY (JF REDDII�IG ��+�.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*** .,.„,,..-. x"� af"� �.. �� . . .. ......„,,,,� n. � _ ��✓� �� ✓� � �a ,� o�.r �.:�^,,,w*"'. �� w �r �� ..l� l�catty 4'ati I3cuk .[�ali�Toiirt��7yf I'�tlr»c+luz!y I ir�cl4rr" w t�,'`L*`�O�l P9:�i r3.c nti\fa��i, r l�:�ci��a 4�r�i�:�.1)rrt�:trwr 12 l�t^t�: r �` r` 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 GI �" Y C� F � � �- ' � ° � � i � CITY OF REDDING �� REPORT TO THE CITY COUNCIL MEETING DATE: September 6,2022 FROM: Tony Van Boekel, Chief ITEM NO. 4.3(a) Information Officer/IT Director ***APPROVED BY*** ry� aw. w ��;�� . �„,.�.�� ° ��. „, rt �, .A,��,� � � w �'� � Pony Va��13oct�v �.hicf Czif�+n�aaFio�t�tAC ic er.'��` �raulcar� .,w �'2SE202? 1�.tplTi,�1 �Cl ��'�� $/�a/�6�� tvanboekel@cityofredding.org btippin@cityofredding.org SUBJECT: 4.3(a)--Transmission Owner and Transmission Operator (TO/TOP) Medium Im act Access Control System 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) wi11 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. Alter�native Action The City Council (Council) could choose to not authorize the system change at the secured facilities and provide alternative direction to staff. Background/Analysis 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 eomply with 147 new standards before the final deadline of November 2022. P�cket Pg.240 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 request 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 requirements 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 requirements 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 solution 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 will 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. Environmental Review This is not a project defined under the California Environmental Quality Act, and no further action is required Council Pr�iority/City Manager Goals This is a routine operational item. P�cket Pg.24�1 ��p��?4S'��i( �W��ti�4�`S��st,f,p��St�� lc�ui��. �i�'�+5��, � '��iu�r��t�FE��a� 40 ��s�� `� � � �� ,, �, ,�� u.0 � i' i . ; . . . , . • � � . rr � . � � �:� � �: ,� � � � � , �:� r � '�. � 1 ' �, ��` � _ ��`��,�„� ,�. t � ��3 � r it '�� i�� j1� 3 .:,,.�. � .ss s�v, ,, � � �� + S n, �� :� i� �, ��', �> ! 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 r 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 r 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" Air c�rt 115k� �elflkr�e Canb Cc�lle ��iew East Reddin Eureka Wa Nlc�c�re,C2c�ad` C7re r�n S�reefi Redd'rn Pc�w�r Sui l�ur C`r�ek T�xas S rin s Waldc�n 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: °�� 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 � � Y , � 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 , !4", ��" ��t,�4.... .'1�.4�i', i.3`�5a. t ,��ru� 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 - i - R.15-Q6-009 COM/CR6/avs 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 .............................. _ il _ 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. - 3 - R.15-Q6-009 COM/CR6/avs 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. -4 - 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: - 5 - 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? - 6 - 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. - 8 - R.15-Q6-009 COM/CR6/avs 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�. - 10 - 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. - 11 - R.15-Q6-009 COM/CR6/avs 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.). - 12 - R.15-Q6-009 COM/CR6/avs 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. - 13 - R.15-Q6-009 COM/CR6/avs 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. - 14 - R.15-Q6-009 COM/CR6/avs 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. - 15 - R.15-Q6-009 COM/CR6/avs 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). - 16 - R.15-Q6-009 COM/CR6/avs 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. _ 17_ R.15-Q6-009 COM/CR6/avs 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. - 18 - R.15-Q6-009 COM/CR6/avs 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 - 19 - R.15-Q6-009 COM/CR6/avs 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. -20 - R.15-Q6-009 COM/CR6/avs 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. -21 - R.15-Q6-009 COM/CR6/avs 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 -22 - R.15-Q6-009 COM/CR6/avs 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. -23 - R.15-Q6-009 COM/CR6/avs 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. -24 - R.15-Q6-009 COM/CR6/avs 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. -25 - R.15-Q6-009 COM/CR6/avs 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. -26 - R.15-Q6-009 COM/CR6/avs 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. -27- R.15-Q6-009 COM/CR6/avs 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 _28 _ R.15-Q6-009 COM/CR6/avs 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 -29 - R.15-Q6-009 COM/CR6/avs 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. -30 - R.15-Q6-009 COM/CR6/avs 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 -31 - R.15-Q6-009 COM/CR6/avs 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 -32 - R.15-Q6-009 COM/CR6/avs 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. -33 - R.15-Q6-009 COM/CR6/avs 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: -34 - R.15-Q6-009 COM/CR6/avs 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 -35 - R.15-Q6-009 COM/CR6/avs 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. -36 - R.15-Q6-009 COM/CR6/avs 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. -3�- R.15-Q6-009 COM/CR6/avs 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. -38 - R.15-Q6-009 COM/CR6/avs 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. -39 - R.15-Q6-009 COM/CR6/avs 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 -4Q - R.15-Q6-009 COM/CR6/avs 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 -41 - R.15-Q6-009 COM/CR6/avs 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). -42 - R.15-Q6-009 COM/CR6/avs 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. -43 - R.15-Q6-009 COM/CR6/avs 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, -44 - R.15-Q6-009 COM/CR6/avs �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 -45 - R.15-Q6-009 COM/CR6/avs 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. -46 - R.15-Q6-009 COM/CR6/avs 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 -47- R.15-Q6-009 COM/CR6/avs 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. _48 _ R.15-Q6-009 COM/CR6/avs 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. -49 - R.15-Q6-009 COM/CR6/avs 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. -5Q - 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. _�1 _ 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 -53 - 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. -54 - 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 -55 - 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 -56 - This Page Intentionally Left Blanlc � � _ , � 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. This Page Tntentionally Left Blank 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. This Page Tntentionally Left Blanlc This Page Intentionally Left Blanlc The Substation Security Map has been redacted due to the con�dential information in the map. This Page Tntentionally Left Blanlc This Page Tntentionally Left Blanlc 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. 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