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1 7. Energy Systems

2 7.1. Introduction

3 The electricity performance expectations and needs of society have increased dramatically over the past 

4 25 years. In fact, the demand for electricity has increased by over 25% since 1990. However, the aging 

5 United States infrastructure is a major issue for all communities. The energy system is making progress in 

6 upgrading the existing electric infrastructure with a focused effort to make the system less vulnerable to 

7 large catastrophic events. For example, many utility providers are installing smart grid technologies; and 

8 grid modernization improvement is a major effort nationwide that is projected to continue for years to 

9 come. This translates to a need to upgrade all elements of the energy infrastructure system and build for 

10 resiliency. In an effort to build resilient and flexible energy infrastructure there needs to be an 

11 understanding and balance of the desired level of resilience, the expected benefits resilience may bring,

12 and the estimated costs associated with improving and replacing this infrastructure.

13 Electricity and fuel are interdependent, essential, and cross-cutting services for community resilience and 

14 reliability. They support society’s most basic human needs for food, water, and shelter. In a hazard event, 

15 electricity and fuel supply are critical to supporting human life and restoration of service is a critical 

16 activity no matter what the cause or where the event occurred. Post-disaster fuel supply is also critical to 

17 electricity generation and transportation. Having available fuel is essential for local generators in

18 managing recovery and for emergency service and supply vehicles.

19 This section discusses the natural gas and liquid fuels subsystems only as they relate to the reliability and 

20 resilience of the electric power system. The pipelines needed to transport natural gas and liquid fuels are 

21 discussed as part of the Transportation System (Chapter 6) because the engineering standards for pipeline 

22 safety and design are administered by the USDOT.

23 7.1.1. Social Needs and System Performance Goals

The electrical and fuel supply societal needs of the 21st 24 century are much different from what these needs 

25 were a century ago. High quality, high availability, inexpensive power has become a basic societal 

26 necessity. Even in day-to-day power delivery, utilities struggle to meet these conflicting consumer 

27 expectations. Preparing for and responding to hazard events becomes an even larger challenge when 

28 utilities need to pay for necessary infrastructure repairs while experiencing revenue losses when 

29 electricity delivery is suspended. This difficult challenge requires careful consideration, especially from 

30 regulatory authorities, when addressing utility rate recovery cases and setting public expectations for post31 disaster recovery timelines and quality of service expectations.

32 As communities address issues related to their expectations of energy system performance, improving 

33 grid resilience and the costs associated with the associated improvements, communicates must prioritize 

34 and balance end user (public safety, hospitals, businesses, and residences) resiliency and restoration 

35 requirements. As much as practical, systems need to adapt to the ever-changing environment and be built 

36 to either minimize damage and impacts to the system, or rapidly restore the system after hazard events 

37 occur. Communities must strike a balance that enables utilities, municipalities and co-operatives to 

38 protect, maintain, and recover the system while controlling costs. Involving additional community 

39 partners may be necessary if performance or restoration expectations are greater than the energy service 

40 provider(s) can economically or practically support.

41 Electricity consumers should be informed and educated on the costs and benefits of facility and 

42 infrastructure hardening and resiliency planning and resulting performance expectations. Generation 

43 facilities (including renewable energy and storage options) and substations may need to be located into 

44 the communities they serve to ensure these facilities are sited and constructed to be resistant to potential 

45 hazards (e.g., flooding, storm surge, wildfire, etc.).
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46 When events occur and recovery efforts are required, the priorities and restoration efforts should address 

47 emergency-related societal needs first, and then progress through a tiered response. Although this model 

48 of recovery can be complex, for simplicity, the three general tiers on which to focus restoration of 

49 services are: 1) emergency facilities and services (Critical and Essential Facilities), 2) critical public 

50 works and right of way (access) for critical infrastructure restoration crews, and then 3) systematic 

51 restoration of the community at large. Later in this chapter (Section 7.3), these tiers are further 

52 investigated for energy systems (by system element such as generation, transmission, and distribution) in 

53 example performance goals matrices. These tiers are discussed in Section 7.5, and are related to recovery 

54 levels for new and existing infrastructure (Sections 7.5.1.2 and 7.5.2.2, respectively).

55 7.1.2. Reliability, Energy Assurance, and Resilience

56 Reliability and resilience are related, but distinct, concepts with different performance goals or metrics. In 

57 many cases, the projects and investments to improve day-to-day reliability contribute to resilience;

58 however there is not a one-to-one correspondence. In August 2012, the President’s Council of Economic 

59 Advisers released a study on the benefits of investing in grid resilience. The study explained the 

60 difference between resilience and reliability as: 

61 “A more resilient grid is one that is better able to sustain and recover from adverse events like 

62 severe weather – a more reliable grid is one with fewer and shorter power interruptions.”

63 In September 2012, Maryland’s Grid Resiliency Task Force adopted similar definitions for resilience and 

64 reliability.

65 “[R]eliability [was defined] as the ability of the bulk power and distribution systems to deliver 

66 electricity to customer during normal „blue sky‟ operations. . . . Resiliency was defined as the 

67 ability of the distribution system to absorb stresses without experiencing a sustained outage.” 

68 The Public Service Enterprise Group (PSEG) in New Jersey states in its Energy Strong Program:

69 “Reliability remains fundamental but is no longer enough now that extreme storms have become 

70 increasingly common and people are more dependent on electricity than ever before.” 

71 PSEG is looking for a different set of performance metrics for all conditions; performance metrics that 

72 have commonality with resilience metrics presented in this framework.

73 For the purposes of this framework, NIST will use the definition of ―resilience‖ from Presidential Policy 

74 Directive/PPD-21: Presidential Policy Directive – Critical Infrastructure Security and Resilience:

75 The term "resilience" means the ability to prepare for and adapt to changing conditions and 

76 withstand and recover rapidly from disruptions. Resilience includes the ability to withstand and 

77 recover from deliberate attacks, accidents, or naturally occurring threats or incidents.

78 Quantitative statistics have not yet been compiled to illustrate the effort the electricity system has put into 

79 resilience, but those in the industry have thought a great deal about resilience. In recent industry studies 

80 (NARUC 2013), NERC defines resilience of the bulk electric system via two main responsibilities –

81 adequacy and security. Adequacy in this context is ―the ability of the bulk power system to supply the 

82 aggregate electrical demand and energy requirements of the customers at all times, taking into account 

83 scheduled and reasonably expected unscheduled outages of system elements.‖ Security is the ―ability of 

84 the bulk power system to withstand sudden disturbances such as electric short circuits or unanticipated 

85 loss of system elements from credible contingencies.‖ This definition of security may be applied to the 

86 bulk electric system, but is not applicable to the distribution system, nor does it address infrastructures of 

87 other systems (e.g., gas/fuels, telecommunications and water).

88 The purpose of this discussion is not to resolve the issue of which term is most appropriate or which 

89 approach will make the infrastructure of the grid least susceptible to damage and outages during all types 

90 of events. Rather, the purpose is to look at the infrastructure elements of the energy system (generation 
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91 facilities, substations, transmission and distribution elements) and provide guidelines and performance 

92 objectives for design and construction of an electrical grid that is more reliable and also more hazard 

93 resistant so as to perform with the least impact or interruption when events (routine, expected, or extreme) 

94 occur. Using the terms related to resilience that are used by the other systems will simplify defining

95 performance metrics for resilience in this and the other systems, allowing us to identify and understand 

96 interdependencies between the different systems. 

97 The Four R’s. When applying the PPD-21 to the energy system to define resilience, a number of

98 scholarly articles and reports on resilience provide an energy industry specific evaluation of what 

resilience can look like. One article, the NASEO State Energy Assurance Guidelines199 refer to the 4 Rs of 

100 resilience with respect to infrastructural qualities:

101 1. Robustness - the inherent strength or resistance in a system to withstand external demands 

102 without degradation or loss of functionality

103 2. Redundancy - system properties that allow for alternate options, choices, and substitutions when 

104 the system is under stress

105 3. Resourcefulness - the capacity to mobilize needed resources and services in emergencies

106 4. Rapidity - the speed with which disruption can be overcome and safety, services, and financial 

107 stability restored

108 An overall energy resilience strategy is one that actively manages each of these qualities to achieve the 

109 desired performance of an energy system. In addition, it can be used to help quantify the following 

110 measures of resilience for various types of physical and organizational systems:

111 1. Technical - the ability of physical systems (including all interconnected components) to perform 

112 to acceptable/desired levels when subject to hazard events

113 2. Organizational - the capacity of organizations - especially those managing critical facilities and 

114 hazard event-related functions - to make decisions and take actions that contribute to resilience

115 3. Social - consisting of measures specifically designed to lessen the extent to which communities

116 and governmental jurisdictions suffer negative consequences due to loss of critical services due to

117 a hazard event

118 4. Economic - the capacity to reduce both direct and indirect economic losses resulting from a 

119 hazard event

120 To explore some differences between reliability and resilience, look at recent events. In the wake of 

121 Hurricane Sandy, widespread power outages had cascading and disastrous consequences across the New 

122 York and New Jersey region, but specifically in lower Manhattan in New York City. The tidal surge 

flooded a substation in lower Manhattan and knocked out power for customers below 39th 123 Street for 

124 nearly five days. "[It was] the largest storm-related outage in our history," according to an October 30, 

125 2012, press release from John Miksad, Senior Vice President for Electric Operations at Consolidated 

126 Edison.

127 The lights in lower Manhattan were hardly back on before Consolidated Edison asked state utility 

128 regulators to approve a very large, multi-year capital investment program to harden the electric power 

129 grid for future storms. Note, resilience hardening is programmed and funded at lower levels than 

130 reliability funding over the same period of time (taken from Pentland 2013) at this utility. 

 

1

This report can be found at :

http://www.naseo.org/Data/Sites/1/documents/publications/State_Energy_Assurance_Guidelines_Version_3.1.pd

f
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131

132 Figure 7-1. Con Edison’s Proposed Capital Budget 

133 This spending demonstrates that even a very large commitment to hardening is still not at the same levels 

134 as reliability spending for this one entity. Is this a trend? Is it representative of the industry as a whole? 

135 The answer to both questions is ―no.‖ Nevertheless the spending plan provides a recent example to help 

136 our understanding of these two initiatives. Reliability can be stated as a ―core goal‖ of electric service. It 

137 can be argued that resilience is a new and growing goal, but is secondary to reliability. There is no clear 

138 formula to designate the appropriate balance between the two; and assigning or measuring expenditures as 

139 attributable to only reliability or resiliency is not always easy. For example, reliability expenditures, 

140 particularly in automation of operations, positively benefit resiliency, so where should these expenditures

141 be tracked?

142 7.1.3. Interdependencies 

143 Energy is a key aspect of resilience. In fact, every other system presented in this framework depends upon 

144 the energy system for the power required to provide a functioning level of resilience for their system. For 

145 example, although a hospital or emergency operations center may not be physically damaged by a 

146 hurricane, flood, or earthquake (a resilience success for buildings), it still may not be functional without

147 power or electricity for sustained and complete operations of all systems and services (presuming the 

148 emergency and backup power systems on site have limitations on the duration and the number of systems 

149 they can power when electricity from the grid is unavailable). 

150 Energy systems also have interdependencies with other systems that reduce effectiveness or resilience. 

151 Some examples are:

152 1. Operations and control centers of utilities rely on the communications and information system to 

153 send and receive operational information to the generation, transmission, and distribution 

154 components within the grid. While the deployment of automated systems to control the switches 

155 and controls within the grid will improve resilience, operational control must still be maintained 

156 at some level or the resilience of the grid will be affected.
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157 2. Liquid fuels rely on the transportation system to ensure the ability to distribute liquid and natural 

158 gas over land (via truck and rail). Disruptions to the transportation system negatively affect the 

159 supply chain and resilience of the energy system (see also 6.2.5 Pipelines for additional 

160 information).

161 3. The ability to recover electricity infrastructure in the electrical subsystem can be seriously 

162 hampered if buildings or transportation system damage is sustained. The response teams, who are 

163 integral to the recovery (and resilience) of the electrical Subsystem, must be able to mobilize and 

164 reach impacted areas. If buildings are destroyed and block access or if roads are impassable due 

165 to catastrophic events, they cannot perform response and recovery activities, making the energy 

166 system less resilient. 

167 Where possible, interdependencies including, but not limited to, those presented here were considered in 

168 preparing the example performance goals presented in Section 7.3.

169 7.2. Energy Infrastructure 

170 Our national infrastructure systems are designed for reliable service with some intent to build a stronger 

171 system due to potential hazard events. While these systems are designed to minimum NESC codes (and in 

172 many areas, beyond the minimum criteria set forth in the codes), the level or magnitude of the event these 

173 systems can withstand without damage is not clearly defined. Over the years, improvements in technology 

174 have addressed some vulnerabilities or risks in the system. However, these improvements in technology

175 may have also inadvertently introduced new vulnerabilities or risks. Recent post-disaster studies and 

176 reports on climate change shed light on why damage and impacts to these systems from the natural hazard 

177 events occurred in the past several years. 

178 The electricity subsystem has spent a great deal of time and money planning, building, rebuilding, and re179 planning for reliability and to support energy assurance goals. While much of that effort pre-dates current 

180 definitions of resiliency, it should still be stated that the electricity subsystem is working to create and 

181 ensure some level of resiliency for communities. The infrastructure continues to improve, with some 

182 improvement actually due to hazard events.

183 The Characteristics of a Resilient Energy System include:

184 1. Planned, modeled, and prepared; ready for immediate and reliable deployment; robust (hardened) 

185 where appropriate

186 2. Supports emergency response, life safety, restoration effectiveness, and socio-economic 

187 continuity during a major event

188 3. Recovers rapidly after catastrophic events

189 4. Incorporates redundancy and spare capacity

190 5. Supports a diversity of energy sources 

191 6. Modular or loosely-coupled architecture

192 7. Aware and responsive to electrical and environmental conditions

193 8. Actively monitored and maintained

194 9. Operates efficiently in non-emergency conditions

195 10. Provides economic and societal benefits to the communities and stakeholders served

196 When designing energy infrastructure, resiliency performance metrics should use common vocabulary, 

197 understood by both providers and consumers, to ensure clear communication, reduce risk, and increase 

198 resilience from different threat and hazard events. Some questions to consider when (re)designing and 

199 establishing performance criteria for the critical components of the energy infrastructure include:
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200 1. Why did failures occur?

201 2. Were the design criteria not correct to account for these hazard events? 

202 3. Can and should higher criteria be used? Or were these hazard events truly rare or extreme events 

203 for which it is not feasible to design the systems to resist with minimal to no impact to the 

204 services they provide? 

205 4. Was the extent and impact of the failures disproportionate to the magnitude of the event that 

206 occurred? And if so, was the degree of the failure or impact due to the design and construction of 

207 the infrastructure or was it a result of, or exacerbated by, the inability to respond/repair the 

208 damage that was caused by the event (i.e., a poor operational response)?

209 These important questions need to be discussed and answered to create a framework that provides design 

210 and construction guidance in the energy industry so generators, distributors, and users of the bulk power 

211 system can set and achieve performance goals. The performance metrics discussed in this guidance must 

212 be discussed in a common vocabulary by both providers and consumers within this industry to have a 

213 chance to reduce our risk and increase our resilience from these different threat and hazard events.

214 7.2.1. Electric Power

215 The electric power subsystem provides production and delivery of electric energy, often known as power, 

216 or electricity, in sufficient quantities to areas that need electricity through a grid connection, which

217 distributes electrical energy to customers. Electric power is generated by central power stations or by 

218 distributed generation. The other main processes are transmission and distribution. This was illustrated in 

219 the NIST Framework and Roadmap for Smart Grid Interoperability Standards, Release 2.0, shown in 

220 Figure 7-2 below.

221

222 Figure 7-2: NIST Smart Grid Conceptual Model (NIST 2012)

223 In 2009, NIST established the Smart Grid Interoperability Panel (SGIP) and developed the Smart Grid 

224 Conceptual Model. This model is used worldwide as a simple mechanism for graphically describing the 
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225 different domains within the Smart Grid. The model is fully described in the NIST Framework and 

226 Roadmap for Smart Grid Interoperability Standards, Release 3.0, which reflects advances in smart grid 

227 technologies and developments from NIST’s collaborative work with industry stakeholders.

228 For simplicity, and to remain focused on the primary resilience components within the bulk power 

229 electrical network, this document will focus primarily on generation, transmission, and distribution. Note 

230 that the natural gas delivery system is very similar in architecture and much of the terminology is 

231 interchangeable with the electricity network when describing the domains.

232 7.2.1.1. Generation

233 Traditional power generation is supported through bulk power plants that incorporate large spinning 

234 electrical generators. In the US, this power is 3-Phase Alternating Current (AC). However, the generation 

235 system is evolving and has been for some time. Prior to deregulation of electricity in certain US states, the 

236 public utilities owned and managed both the generation (power plants) and the transmission grid over 

237 which electricity was delivered. Deregulation separated generation and transmission, with most 

238 deregulated states allowing independent power producers (IPPs) to competitively develop generation 

239 projects. The term ―deregulation‖ does not imply these utilities are not highly regulated, simply that 

240 consumer choice exists, although IPP developers must still negotiate contracts to sell power to the utilities 

241 who maintain their responsibility to manage and deliver the electricity via the grid. The US today is a 

242 patchwork of regulated and deregulated states so, depending on the state, the utility could control 

243 transmission, generation, or both. This patchwork of regulation and deregulation at the state level also 

244 applies to the distribution of natural gas by utilities.

245 In addition, renewable power projects, distributed generation by commercial entities, and demand-side 

246 management (such as demand response and energy efficiency and energy storage) are becoming more 

247 pervasive. Today the term ―generation‖ increasingly includes ―virtual generation,‖ resulting from using

248 load-reduction to offset power demand or the use of storage rather than developing new generation 

249 (power plants). Additionally, more of this activity is evolving to be located behind the meter at homes and 

250 businesses (rooftop solar, smart meters, etc.).

251 Renewable power comes in many forms – wind, solar, biomass, hydropower. In some states energy-from252 waste (waste-to-energy) plants also meets the definition of renewable power. The public is well-versed in 

253 the term ―renewable power,‖ but does not typically understand that the rules vary from state to state in the 

254 same way the Renewable Portfolio Standards (RPS) or goals for the percentage of power to be generated 

255 from renewables vary by state.

256 ―Distributed generation‖ is an umbrella term typically describing power plants developed for a specific 

257 company or industrial location, also known as ―in-the-fence‖ power, which serve the needs of a particular 

258 commercial plant, manufacturing facility or industrial park. These plants must be developed in 

259 accordance with requirements for their particular state, but are typically single or small group load260 serving entities. An example might be an industrial facility that builds its own on-site power plant to serve 

261 its electric power supply needs. Often these generating plants are also cogeneration facilities, providing 

262 steam for a host establishment or a neighboring industrial/commercial facility for heat or another 

263 industrial process use. Many of these smaller facilities are also referred to as Combined-Heat and Power 

264 or CHP plants.

265 In regulated states Demand Side Management (DSM) is best defined by the Energy Information 

266 Administration: ―the planning, implementation, and monitoring of utility activities designed to encourage 

267 consumers to modify patterns of electricity usage, including the timing and level of electricity demand.‖

268 Thus, DSM can include both Energy Efficiency (EE) or Demand Response (DR) to reduce electric 

269 demand.

270 Energy Efficiency at the utility level is a method or program by which the utility manages or reduces the 

271 demand for power rather than building or contracting for new generation (power plants) or having to 
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272 purchase additional power on the spot market, which can be extremely expensive. These programs can be 

273 high-level state-wide improvements to public buildings (efficient light bulbs, improved insulation, etc.) or 

274 can entail distribution of energy efficient light-bulbs or sophisticated meters and thermostats for 

275 residential users.

276 Demand Response (DR) is sometimes implemented by a non-utility company that enters into a contract 

277 with electric users, usually large users such as universities, high-rise office buildings, chains of retail 

278 stores etc., and pays those users to lower their electric use during times of peak demand such as hot 

279 summer days. In doing so, the DR company sells that reduced-load to the utility during peak demand 

280 periods. This allows large users of electricity to lower their annual electric costs via the DR payment and 

281 allows the utility to avoid brown-outs or black-outs and avoid spot market purchases or the need to 

282 develop new generation. 

283 Energy Storage comes in many forms, from large-scale batteries, to pump storage, to fuel cells. In the 

284 case of pump storage, which has a long history, water is pumped up to a dam or holding basin during 

285 periods of low electric demand (non-peak-periods) so it can be released during periods of high demand to 

286 meet load. This historical use of pump storage is now being expanded to use compressed air and other 

287 technical methods of delayed release of energy, such as flywheels, during peak periods.

288 As noted earlier, the belief that generation satisfies electric demand is only partly true. Using alternative 

289 methods to reduce, offset, or delay peak electric demand plays a larger role and, as such, needs to be 

290 considered as a key part of the system by which reliable and efficient power to the US population is 

291 ensured.

292 7.2.1.2. Transmission

293 In the traditional bulk power system, 3-Phase power exits the generator and enters a transmission 

294 substation. Voltages are transformed to very high voltages to travel long distances along three separate 

295 transmission lines, each carrying a single phase. The transmission infrastructure is primarily wire and 

296 towers carrying high voltage power from generators to distribution substations. It is the ―middle-man‖ of 

297 the electric power delivery network.

298 The overarching issues surrounding the vulnerabilities of the transmission infrastructure stem from the 

299 aging physical assets today. As overall customer load requirements grow and the various federal and state 

300 regulations change, there is a need for more robust and flexible electric power delivery systems to keep up 

301 with demand. The emergence of the renewable generation market, and the transition from coal generation

302 to natural gas generation, has begun new stresses on the power grid beyond its original design. Electrical

303 flows that were designed to be in one direction are now in multiple directions, depending on the 

304 generation available at any particular time of day. Transmission constraints, which affect cost and 

305 reliability, have become common in operations. 

306 Recently (over the last 10 years), transmission planning has evolved from relatively few new transmission 

307 lines being built nationwide to many new transmission lines being planned by most major utilities. The 

308 cost and time to build new transmission lines have also increased significantly over the years due to 

309 public routing, regulatory and environmental restrictions. But the performance of these transmission lines 

310 has improved with the passage and implementation of FAC-003-3 Transmission Vegetation Management 

311 Program. The purpose of FAC 003-3 is to provide the guidance needed ―to maintain a reliable electric 

312 transmission system by using a defense-in-depth strategy to manage vegetation located on transmission 

313 rights of way (ROW) and minimize encroachments from vegetation located adjacent to the ROW, thus 

314 preventing the risk of those vegetation-related outages that could lead to Cascading.” 

315 All of these demands impact electric transmission system reliability. Ever-increasing cyber-based 

316 monitoring systems are being developed to reduce the impact of any potential hazard. As new systems are 

317 engineered and constructed there is also a need to evaluate ongoing maintenance. Many efforts are 

318 underway to strengthen our nation’s transmission systems. Several major Smart Grid transmission 
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319 projects have been initiated and, in some cases, recently completed to supply power across the nation. 

320 Other efforts to increase the power grid’s resiliency and efficiency include developing and deploying new 

321 technologies (e.g., Demand Response, Micro-grid/Islanding, Synchrophasers (PMU), Dynamic Transfer, 

322 Energy Imbalance Markets (EIM) and Dynamic Line Rating (DLR)). The FERC also issued Order 1000, 

323 meant to reduce capital costs of transmission for end consumers by introducing competition between 

324 utilities and transmission developers.

325 Transmission infrastructure is vulnerable to a number of hazards. Storms with heavy rain (e.g., 

326 hurricanes) can cause flooding of low-lying electrical infrastructure including substations as was the case 

with Hurricanes Sandy and Irene2327 . The heavy rain that accompanies many thunderstorms and hurricanes 

328 adds to the hazards from debris, by potentially washing away the foundations of poles on the sides of hills 

329 and exposing underground cabling to the movement of water. There are other examples of flood hazards 

330 and events, (ranging from tsunamis, to dam failures, to large water main breaks) that can also cause water 

331 to follow electrical lines back to underground electrical conduits and vaults and will have a negative 

332 impact on underground substations and splices. 

333 Flooding is not the only hazard that threatens damage and failures of the electric power infrastructure. 

334 Strong winds, such as those from tornadoes, hurricanes, and even thunderstorms, can damage electrical 

335 infrastructure. Large thunderstorms tend to have strong straight line wind and can destroy trees and 

336 structures quickly. 

337 Another potential hazard that can impact electrical power infrastructure is wildfire. Wildfires are a routine 

338 part of life in some communities across the country. Depending upon the wildfire risk, communities may 

339 need energy resiliency measures to protect against them. Every year, wildfires burn thousands of acres 

340 and destroy homes and other structures. Electrical lines have been implicated in starting wildfires, as was 

the case in the 2007 San Diego Witch Creek, Guejito and Rice wildfires3341 .

342 7.2.1.3. Distribution

343 In the traditional power delivery system, the distribution system begins at the distribution substation. The 

344 substation takes power that is normally delivered at 10s or 100s of thousands of volts and transforms the 

345 voltage to less than 10k volts (typically 7200 volts). The distribution substation is a critical piece of the 

346 overall power delivery system and is a focus area for resiliency hardening and post-disaster repair. It 

347 supports a variety of Operations Technology (OT) and Information Technology (IT) equipment and 

348 systems that connect the endpoint loads to the utility’s operation center. The distribution system is by far 

349 the largest component of the electricity network. With regard to recovery operations, the majority of focus 

350 is normally within the distribution network.

351 Given the aging infrastructure, some real vulnerabilities exist in the energy distribution systems. The 

352 distribution systems are typically built and constructed along roadsides but, in some cases, they run 

353 through less accessible back lots and other right-of-ways. As overall customer load requirements grow

354 and the changes in regulations continue, there is a need for more robust electric systems; but the ability to 

355 provide these robust electric systems is struggling to keep up with the demand.

356 Maintaining the designed distribution systems is also a challenge. The poles and equipment that are key 

357 elements of the distribution system are subject to overloading with additional wire and system 

358 components by local service providers who add lines and equipment to existing poles. These additions 

359 may directly overload the components that make up the electrical system or increase their vulnerability to 

360 wind and ice during storm events. 

 

2

United Illuminating announces $11M flood prevention project for substations, July 23, 2013, 

http://connecticut.news12.com/features/sandy/united-illuminating-announces-11m-flood-prevention-project-forsubstations-1.5753215, retrieved 27-July-2013

3

Power lines cited as cause of largest wildfires". SAN DIEGO UNION-TRIBUNE. 2007-11-16. Retrieved 2013-7-27.
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361 Further, as new systems are engineered and constructed there is a need to evaluate the ongoing 

362 maintenance. One element of maintenance in the forefront along the distribution system is tree coverage.

363 Most, if not all, utility entities have well-established and adequate tree management programs; but failure 

364 to implement these programs has been a leading cause of outages. The reason for this failure is not always 

365 simple. Even though the utility may have an established and programmed vegetation management 

366 program, public and private land owners may not allow removal of any trees or limbs. Other jurisdictions 

367 and environmental entities (state, local, or activist) have also succeeded in stopping tree trimming and 

368 clearing programs. Further, the health of trees and vegetation (as well as insect infestation and other 

369 natural scenarios that can diminish the performance of trees) should be anticipated and addressed in 

370 planning and maintenance programs. The aggregate impact of these actions results in failed 

371 implementation of the tree trimming programs, which creates a critical failure point where system 

372 vulnerability continues to worsen instead of being mitigated. These tree maintenance programs should 

373 consider local factors that can also impact the performance of trees and vegetation and result in localized 

374 areas of poor performance during storm events that, if not accounted for, would directly impact the 

375 performance of the Distribution Systems.

376 As discussed for transmission, many cyber-based monitoring systems are being developed annually to 

377 reduce the impact of any potential natural hazard such as the hurricanes and flooding.

378 Many efforts are underway to strengthen our nation’s distribution systems. There are major feeder 

379 hardening program/projects underway across the nation. These projects have been focusing on dead-end 

380 cross arms, lightning arresters at any identified weak points. In California there is a push for strengthening 

381 the systems from fires. They are now ―boxing in‖ fuses so no hot metal will hit the ground and potentially 

382 cause fires. Dependent on the location nationally, there has also been a movement away from wood poles.

383 Where wooden poles are still being used, they are increasing the size and class to accommodate the 

384 overall design constraints. 

385 The electric energy distribution system is vulnerable to a number of hazard events. Overhead distribution 

386 lines are particularly vulnerable to high wind hazards, such as hurricanes and tornadoes. However, most 

387 infrastructure failures from wind storms are not from the wind loading directly. Trees often fall onto 

388 infrastructure, causing damage and failures to the distribution network. Many neighborhoods have large 

389 trees that parallel the overhead infrastructure; and in many cases conductors may actually run through the 

390 trees. Therefore, vegetation management is critical to minimizing vulnerability of distribution lines to 

high wind events4391 . It only takes one property owner resisting a utility tree trimming program to trigger a 

392 power outage affecting a large number of people. 

393 The constant push of high winds on utility poles can slowly cause them to lean. Pole toppling events can 

394 occur several days after a storm. Heavily loaded poles can be braced if they are likely to be exposed to

395 high straight line winds. Winds that change direction around the clock, such as those experienced in 

396 Florida at the end of the 2007 hurricane season, can do more damage than storms where the wind comes 

397 from one direction. If it is solidly packed, the pole can crack off at ground level or another weak point. As 

398 a result of the observations after the 2007 hurricane season, Florida now requires more pole inspections to 

399 look for overloaded poles and poles that show rot at the interface with the ground or other weakness. 

400 Instead of a 15-year pole inspection cycle, Florida is considering a 7-year inspection cycle. Poles that look 

401 perfectly fine from a visual inspection may not be fine internally or underground. Therefore, new 

402 inspection tools and techniques have been developed to help with pole inspection.

403 Another hazard associated with high wind events such as hurricanes, tornadoes, and thunderstorms is 

404 lightning, which is a particular concern for electrical energy infrastructure. When a transformer is 

405 overloaded, either by a direct lightning strike or by an overload on the circuit, it typically flashes to a 

 

4

EPRI Report 1026889, Enhancing Distribution Resiliency, Opportunities for Applying Innovative Technologies, 

January 2013
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406 roaring blaze quickly. The resulting blaze can consume not only the transformer, but the pole it is on and 

407 the close vegetation as flaming oil falls to the ground. Lines can come down from direct lightning strikes, 

408 especially on poles that have hollowed out over time and filled with water. These poles literally explode 

409 when the water inside flashes to steam. 

410 Lightning will travel down a conductor until it finds an easier path to travel. Even when a line is already 

411 down and de-energized, lightning can strike it traveling the remaining path, until it finds a lightning 

412 arrestor or a fusible link. Damage to home appliances and consumer electronics is common when 

413 lightning strikes a line beyond an outage point. Reminding people to unplug appliances and other 

414 equipment in a major storm is the best way for them to protect this equipment. Having back up or standby

415 power for critical communications needs and data gathering in emergency centers that are fully up to date 

416 on software and data is important, even in mobile command posts. Having that back up equipment that is 

417 simply stored and not connected to the grid is a good approach to redundancy and resiliency. Too often,

418 backup equipment is used to provide additional capacity on a day-to-day basis, only to leave the location 

419 with no working equipment after lightning strikes. Surge protectors, uninterruptible power supply (UPS) 

420 systems, and other protection equipment is helpful, but only having the equipment unplugged from the 

421 wall is 100% insurance that a lightning strike will not disable it.

422 Earthquakes can also cause damage to electrical infrastructure. Earthquakes can do widespread damage to 

423 the electrical infrastructure with little or no warning. In addition to directly damaging electrical 

424 infrastructure, they can cause other failures, such as fires and ruptured water mains, which may in turn 

425 cause damage to electrical infrastructure. 

426 Earthquakes that cause ground movement in close proximity to the fault may damage towers and poles or 

427 break electrical lines that cross the fault or run parallel to the fault line. Those lines tend to snap because 

428 there is not enough slack in the line to allow it to flex with the movement of the fault line, or the 

429 movement is so rapid that the line’s slack cannot move quickly enough. Overhead lines on proper 

430 structures tend to perform better than underground lines near major earthquakes because the lines all have 

431 some slack (the sag of the centenary) in them and their supporting structures flex as well. 

432 Top loaded poles (those with transformers, voltage regulators, etc.) tend to fail first in an earthquake, all 

433 things being equal with the footing of the pole and the quality of the pole. It is better to ground mount this 

434 type of equipment if the poles are close to a fault line.

435 7.2.1.4. Emerging Technologies

436 Many smart grid technologies available today are targeted to help the electric utility significantly in

437 improving reliability, operating efficiency, and power quality, and in identifying potential opportunities to 

438 harden the current circuits from a resiliency standpoint. Many technologies, considered ―plug and play,‖ 

439 are working together nicely with the right infrastructure. Many utilities are also evaluating their smart grid 

440 plans and working on full integration to allow for predictability as well as corrective action. 

441 Technology has also allowed the utilities to rapidly correct power outage situations. Many utilities have 

442 implemented some form of distribution automation with very good results. These results have led to 

443 further technological advancements, being implemented today. Today’s utilities recognize the real need to 

444 build a resilient, safe, and economical electrical network. As the utilities computerize the electric grid,

445 they are opening additional opportunities for predictability and better understanding of communities’

446 usage.

447 Microgrids

448 With regards to energy resiliency, one of the most profound emerging technology opportunities is 

449 microgrids. Microgrids connect loads with Distributed Energy Resources (DERs) within a defined 

450 boundary. The ―macro‖ grid treats the DER as a single entity; the microgrid manages the DERs and loads 

451 independently. Microgrids can be connected or disconnected from the grid and can operate independently 
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452 in an islanded mode. They offer a variety of compelling business opportunities to help meet 

453 organizational mission requirements, participate in electricity markets, increase energy surety/resiliency, 

454 and incorporate renewable energy resources.

455 Microgrids can be implemented at numerous points in the electric power system physical hierarchy –

456 transmission, subtransmission, substation, distribution, and consumer. The most fundamental division of

457 location however is customer-side or utility-side implementation. Customer-side microgrids can be 

458 designed and implemented with the specific operational and business requirements of the facility in mind.

459 Customer-side microgrids can be thought of as an extensive, highly managed extension of an emergency 

460 generator backup system. The difference is that a microgrid is designed to provide full energy services for 

461 an extended period of time. A customer-side microgrid can be implemented to ensure business continuity 

462 during a major natural hazard. Recently a major Fortune 100 corporation included a microgrid as part of 

463 their new company campus headquarters design to allow full operation of the facility for an unlimited 

464 time in the aftermath of an earthquake. A clear business case could be made for implementing such a 

465 microgrid by extracting value from the technology during normal operations. In contrast, a utility-side 

466 microgrid has the challenge of being funded using the existing utility regulatory model for technology 

467 investment. Many more stakeholders are involved in deciding whether the investment required is prudent.

468 Microgrids have been studied as a potential grid hardening solutions by New York, Connecticut, and 

469 California, as well as the U.S. Department of Energy. These studies also consider some of the current 

470 regulatory frameworks hindering widespread deployment.

471 There are 6 primary requirement areas to consider when designing a microgrid, which are substantially 

472 different for customer-side versus utility-side implementations:

473 1. Mission: What is the organization’s mission? How will a microgrid help support the mission?

474 2. Loads and Generation: What are the existing and future loads that will need to be addressed by 

475 the microgrid? What are the existing suitable generation resources available?

476 3. Infrastructure: How is the current grid configured? How will the microgrid interact and take 

477 advantage of what is already there? How do the infrastructure elements need to be monitored and 

478 controlled to ensure stable operation and meet operational goals?

479 4. Scenarios: What are likely events (typical, emergency, opportunistic) that a microgrid can 

480 support?

481 5. Policy: What policies, incentives, and constraints need to be considered?

482 6. Costs: What are current and projected costs of the system?

483 Microgrids are not simple, interchangeable systems. They require a good business case, should operate 

484 and provide value when the grid is operational, and require long-term operational expertise and 

485 maintenance commitment. However, in some cases the economic and business value for microgrids may 

486 pencil out when loss of critical operations poses a significant risk to public safety or security. Resiliency487 related candidates to consider microgrid solutions include:

488  Critical facilities for critical events (City Hall, Police, Fire, 911, etc.)

489  Hospitals and medical centers

490  Local government facilities

491  Federal facilities and military bases

492  Key businesses including grocery stores, drug stores, large employers, gas stations

493  Schools, colleges, and universities

494 Each of these candidates could be serviced by a customer-side or a utility-side microgrid – or a hybrid 

495 approach where the customer side is integrated with a utility-side system to provide enhanced flexibility.

496 All of the following technologies are potential elements of a utility or customer side microgrid:
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497 Renewable Energy Generation

498 Renewable energy comes from natural sources that are constantly and sustainably replenished. When 

499 power is interrupted, renewable energy generation can continue to support uninterrupted or reduced 

500 capacity service to energy consumers. Although it is arguable that renewable energy is not emerging 

501 technology, the equipment, software, and systems are rapidly becoming pervasive and are maturing at a 

502 very accelerated pace. The two primary emerging renewable energy generation resources are solar and 

503 wind. 

504  Solar Photovoltaic (PV) - The photovoltaic process converts light into electricity. Solar cell 

505 modules supply DC electricity at a certain voltage (e.g. 12 VDC). The amount of current is 

506 directly dependent on the amount of light that enters the module. When multiple modules are 

507 strung together, a solar (or PV) array is constructed that can produce larger quantities of 

508 electricity. PV arrays are configured in series or in parallel in order to provide different voltage 

509 and current combinations. PV systems are being used in a variety of scenarios, ranging from 

510 small rooftop supplemental power all the way to large solar farms providing many megawatts 

511 (MW) of power. The technology continues to improve with higher efficiency conversions of light 

512 into electricity and stronger, lighter, more flexible materials.

513  Wind Power - Wind power is one of the oldest forms of renewable energy and has been 

514 harnessed by man for many centuries. The basic process uses turbines to capture the wind’s 

515 energy, convert to kinetic, spinning energy, and convert the energy into mechanical power. The 

516 resulting mechanical power has been used historically to pump and move water, and in mills to 

517 grind grain and corn. It can also be used to create electricity through a generator. Although the 

518 same basic principles are at work, wind generation today is significantly different than those of 

519 our ancestors, primarily due to scale. Farms of wind generators are found throughout the 

520 Midwest, Texas, the coasts, and deserts. Some wind farms produce many megawatts (MW) of 

521 power. The technology trend is better aerodynamics for more efficient conversion of kinetic wind 

522 energy to electricity, more efficient and smarter generators, and larger, more powerful wind 

523 turbines.

524 Fuel Cells and Storage

525  Fuel Cells - Fuel cells create electricity through chemical reactions. The reaction is controllable 

526 and can be tuned to manage the amount of electricity produced. The types of fuels vary, but 

527 require oxygen and hydrogen in their chemistry. The waste from fuel cells is clean, producing 

528 H2O. Fuel cells have a variety of uses and have been popular concepts in the automotive industry 

529 to support environmentally-friendly hydrogen vehicles. The technology continues to involve with 

530 different fuel sources, cheaper solutions, and higher capacities.

531  Battery Energy Storage - Battery storage systems are the next ―killer app‖ for energy resiliency, 

532 power quality, and energy efficiency. The concept is simple: when demand is low, charge the 

533 batteries; when demand is high or the system is stressed, use battery power. Battery power today 

534 is in the same place technologically that solar power was in the 1990s. Batteries are too big, too 

535 expensive, and don’t last long enough. Also, there are very few incentives for investment in 

536 battery technology. The landscape is slowly changing and states like California are performing 

537 battery studies and pilots. This emerging technology could have an enormous impact on how the 

538 grid is managed and combined with renewable energy generation, simple microgrids become 

539 viable, affordable solutions and our energy becomes more resilient.

540 Demand-Side Management

541 The ability for customer-side loads to respond to external controls during an energy system emergency is 

542 a key element of energy system resiliency during the event while restorative actions are underway. This is 

543 especially important when microgrids are used on the customer side and/or utility side of the meter. A key 

544 challenge in managing a microgrid is maintaining load/generation balance to keep the system stable.
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545 Simple customer side backup generation solutions that are not intended for long term operation and 

546 support of normal business operations typically only supply emergency loads. More sophisticated systems 

547 that integrate renewable energy sources, fuel cells, and energy storage may utilize a building automation 

548 system to control building loads to optimize the performance of the system for short or long term 

549 operation. Utility-side microgrids may also use demand side management systems (DMS) to effectively 

550 manage feeder and substation level microgrids to ensure system stability and maximize the number of 

551 customers that can be served by those portions of the system that remain intact after a major event and 

552 come on line during restoration. DSM techniques can also be used at the bulk level to manage temporary 

553 transmission and subtransmission loading constraints that may exist during a major event.

554 7.2.2. Liquid Fuel

555 The most common liquid fuels are gasoline, diesel, and kerosene-based products, such as jet fuels, which 

556 are produced from petroleum. Other liquid fuels include compressed natural gas, liquefied petroleum gas

557 (LPG), synthetic fuels produced from natural gas or coal, biodiesel, and alcohols. For resiliency, liquid 

558 fuels are critical to back-up power generation and nearly all modes of transportation. In addition, 11% of 

559 U.S. homes rely on heating oil or propane, with heating oil usage concentrated primarily in the Northeast 

560 and propane usage concentrated in rural areas (USEIA 2009).

561 Although less than 1% of all electricity in the U.S. is generated in oil-fired plants, there are some isolated 

562 markets in which petroleum remains the primary fuel. The leading example is Hawaii, where more than 

563 70% of electricity generation is fueled by petroleum (USEIA 2014a). 

564 Potential failure points for liquid fuel production, storage, and distribution include:

565 1. Catastrophic loss of major production fields

566  Fires

567  Blowouts

568  Spills

569 2. Transport of crude oil from production sites to refineries

570  Ports

571  Pipelines

572  Rail

573 3. Processing at refineries into finished products

574  Onsite storage of raw materials

575  Onsite piping

576  Processing reactors vessels

577  Power supply (grid or backup)

578  Onsite storage of finished products and by-products

579 4. Transport from refineries to regional distribution centers

580  Ports

581  Pipelines

582  Rail

583 5. Storage at regional distribution centers

584  Aboveground tank farms are the most common storage systems used at permanent depots

585 6. Regional distribution

586  Pipelines (e.g., pipeline from Oregon’s CEI Hub to Portland International Airport)

587  Trucks (e.g., distribution from Port of Tampa to Orlando-area fuel stations)
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588 7. End user or retail sale

589  Onsite storage (e.g., above ground tanks at an airport or buried tanks at a retail fuel station)

590  Power for pumps at retail distributors (e.g., New Jersey retail fuel station grant program 

591 described below in Section 7.3.4)

592 Maintaining production of crude oil and safely transporting it to refining centers (Steps 1 and 2) are major 

593 national and international security issues that are beyond the scope of this framework.

594 US refineries (Step 3) tend to be geographically concentrated and operate at 90% or more of capacity 

595 during periods of strong economic growth (USEIA 2014b). The reliability and resiliency of US refinery 

596 capacity is both a national security issue and a major regional economic issue in those areas of the US 

597 where refinery capacity is concentrated.

598 Regardless of where production and refinery capacity are located, all communities should assess their 

599 resiliency with respect to Steps 4-7. Damage to ports, tank farms, pipelines, railways or roadways can 

600 cause serious delays to the distribution of liquid fuels which, in turn, can lead to loss of backup power 

601 generation when onsite fuel supplies are exhausted and disruptions to all modes of transportation. In cold 

602 weather scenarios, an extended disruption to heating fuel supplies also has the potential of becoming a 

603 significant issue.

604 Steps 4-7 focus on the energy portion of the Oregon Resilience Plan, which was developed for a 

605 magnitude 9.0 earthquake scenario on the Cascadia subduction zone. The Oregon study identifies the 

606 northwest industrial area of Portland along the Willamette River as Oregon’s Critical Energy 

607 Infrastructure (CEI) Hub. More than 90 percent of Oregon’s refined petroleum products pass through this 

608 six-mile stretch along the lower Willamette River before being distributed throughout the state. For the 

609 Cascadia earthquake and tsunami scenario, potential hazards to liquid fuel storage and distribution 

610 networks include ground shaking, sloshing, liquefaction, lateral spreading, landslides, settlement, bearing 

611 capacity failures, fire, or seiches in the CEI Hub area and tsunami damage at the coast. Fuel is transported 

612 to the site via a liquid fuel transmission pipeline from the north and marine vessels. Alternative modes of 

613 transporting fuel from the east or south or by air are very limited. Key recommendations for improving 

614 the resiliency of the Oregon energy system include conducting vulnerability assessments, developing 

615 mitigation plans, diversifying transportation corridors and storage locations, providing alternate means of 

616 delivering fuels to end users, and coordinated planning (OSSPAC 2013).

617 The American Lifelines Association (ALA 2005) identified the high-level performance measures and 

618 performance metrics for pipeline systems shown in Table 7-1.

619 Table 7-1. The American Lifelines Association High-Level Performance Measures and Performance 

620 Metrics for Pipeline Systems (ALA 2005). 

Desired Outcomes 

(Performance Targets)

System Performance Metrics

Capital 

Losses ($)

Revenue 

Losses ($)

Service Disruption (% 

service population)

Downtime 

(hours)

Casualties 

(deaths, 

injuries)

Lost 

Product

Protect public and utility personnel safety X X

Maintain system reliability X X

Prevent monetary loss X X X X X

Prevent environmental damage X

621 A qualitative ranking of hazards to typical pipeline system components and facilities from the ALA 

622 (2005) study is reproduced in Table 7-2.

623
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624 Table 7-2. Qualitative Ranking of Hazards to Typical Pipeline System Components and 

625 Facilities (ALA 2005). 

Hazards

Degree of Vulnerability

Transmission PipelinesPump StationsCompressor StationsProcessing FacilitiesStorage TanksControl SystemsMaintenance Operations Buildings and EquipmentPressure Regulations /Metering StationsDistribution PipelinesService Lines or Connections

Natural Hazards

Earthquake Shaking L M M M H M H L L M

Earthquake Permanent Ground Deformations (fault rupture, 

liquefaction, landslide and settlement)

H - - - L - - L H (Buried) M

Ground Movements (landslide, frost heave, settlement) H - - - L - - L H (Buried) M

Flooding (riverine, storm surge, tsunami and seiche) L H H H M H H H L M

Wind (hurricane, tornado) L (Aerial) - - - - L L - - -

Icing L - - - - - - - L -

Collateral Hazard: Blast or Fire M H H H H M L L L M

Collateral Hazard: Dam Inundation L H H H M H H H L M

Collateral Hazard: Nearby Collapse - L L L - L L L M L

Human Threats

Physical Attack (biological, chemical, radiological and blast) M M M M - M M - M -

Cyber Attack - L L L - H L - L -

626 Note: Degrees of vulnerability: H = High, M = Moderate, L = Low. When a component or system is located within a building the 

627 vulnerability of both the building and component should be considered. For example, where there is a potential for building 

628 collapse or mandatory evacuation, the equipment housed within is at risk. The entries in Table 7-2 assume that the component is 

629 of recent vintage, i.e., post 1945.

630 7.2.3. Natural Gas

631 Natural gas pipelines and storage facilities comprise a vast natural gas infrastructure that services 65 

632 million homes, 5 million businesses, 193,000 factories and 5,500 electric generating facilities

633 (McDonough 2013). There are nominally over 2.4 million miles of natural gas pipelines in the continental 

634 US, with pipelines running along roads and private easements under both urban and rural lands 

635 (McDonough 2013). Steps need to be taken to safeguard this massive and ubiquitous part of our energy 

636 infrastructure from disastrous events.

637 Natural gas pipelines can be damaged via ground shaking, liquefaction, and ground rupture. Specific 

638 points of failure may be predicted when rupture or liquefaction occurs; but the most damaging event on a 

639 wide scale is ground shaking (Nadeau 2007). Existing weaknesses, which serve as the first points of

640 failure, can include corrosion, bad welds, and weak or strained material. Regular maintenance can have a 

641 beneficial effect, as can upgrading piping from iron (used in older pipeline) to plastic (used for low642 pressure distribution lines) or even steel. Extensive work has been done to develop models that predict the 

643 impact of natural hazards on natural gas systems, which can help leaders determine the risk to their local 

644 facilities. 

645 Generation, in addition to piping, needs to be resilient to hazard events. Fuel cells, which generate power 

646 via electrochemical reaction rather than combustion, are already being used as a means to achieve a more 

647 resilient natural gas infrastructure. Fuel cells provide a decentralized, reliable source of power that has 

648 proven useful in hazard events. They are considered a distributed resource by IEEE. For example, during 

649 Hurricane Sandy, one manufacturer put 60 fuel cells in place to provide backup power to cell phone 

650 towers. Thanks to the inherent resilience of underground natural gas systems to non-seismic events, these 
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651 cell towers remained operational during and after the storm. Notably, they were the only cell towers in the 

652 area to remain operational throughout the event (Fuel Cell and Hydrogen Energy Association 2014).

653 Aboveground facilities (e.g., compressor stations, processing plants, meter stations, and wells) are the 

654 most vulnerable parts of the natural gas system. Natural gas pipes and storage facilities are inherently 

655 protected from many hazard events by being underground, but the facilities aboveground are subject to all 

656 the same risks as other commercial structures. For example, unusually cold weather in 2011 caused 

657 interruptions in natural gas service in the Southwest, which, in turn, caused outages at gas-fired electric 

658 generating facilities that were experiencing high demand for electricity. A joint report by FERC and 

659 NERC concluded these outages and disruptions of service were caused by weather-related mechanical 

660 problems such as frozen sensing lines, equipment, water lines and valves. The report recommended 

661 adopting minimum winterization standards for natural gas production and processing facilities, and 

662 suggested that additional underground natural gas storage capacity in the region could have ameliorated 

663 the impacts of natural gas supply shortages. In addition to the issues discussed in the section about 

664 structure resilience, there are vulnerabilities specific to natural gas facilities – flammability and high 

665 pressure hazards, and issues with the surrounding infrastructure. These special vulnerabilities should be 

666 recognized and accounted for in addition to the steps taken to mitigate inherent risks of aboveground 

667 buildings.

668 7.2.4. Emergency and Standby Power

669 Loss of offsite power delivered by the commercial power grid can be triggered by failures in power 

670 generation, transmission, or distribution systems or by disruptions to power plant fuel supplies. The 

671 vulnerability of offsite power to nearly all hazards and the dependence of nearly all buildings and 

672 infrastructure on offsite commercial power combine to make both emergency and standby power key 

673 requirements for improving disaster resilience.

674 IEEE (1995) defines an emergency power system as ―an independent reserve source of electric energy 

675 that, upon failure or outage of the normal source, automatically provides reliable electric power within a

676 specified time to critical devices and equipment whose failure to operate satisfactorily would jeopardize 

677 the health and safety of personnel or result in damage to property.‖

678 The National Electric Code (NFPA 2005) defines emergency systems as ―those systems legally required 

679 and classed as emergency by municipal, state, federal, or other codes, or by any governmental agency 

680 having jurisdiction. These systems are intended to automatically supply illumination, power, or both, to 

681 designated areas and equipment in the event of failure of the normal supply or in the event of accident to 

682 elements of a system intended to supply, distribute, and control power and illumination essential for

683 safety to human life.‖

684 The NEC (NFPA 2005) divides standby power systems into two categories:

685  “Legally Required Standby Systems: Those systems required and so classed as legally required 

686 standby by municipal, state, federal, and other codes or by any governmental agency having 

687 jurisdiction. These systems are intended to automatically supply power to selected load (other 

688 than those classed as emergency systems) in the event of failure of the normal source. Legally 

689 required standby systems are typically installed to serve loads, such as heating and refrigeration 

690 systems, communications systems, ventilation and smoke removal systems, sewage disposal, 

691 lighting systems, and industrial processes that, when stopped during any interruption of the

692 normal electrical supply, could create hazards or hamper rescue and fire-fighting operations.‖

693  “Optional Standby Systems: Those systems intended to supply power to public or private 

694 facilities or property where life safety does not depend on the performance of the system. 

695 Optional standby systems are intended to supply on-site generated power to selected loads either 

696 automatically or manually. Optional standby systems are typically installed to provide an 

697 alternate source of electric power for such facilities as industrial and commercial buildings, 
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698 farms, and residences and to serve loads such as heating and refrigeration systems, data

699 processing and communications systems, and industrial processes that, when stopped during any 

700 power outage, could cause discomfort, serious interruption of the process, damage to the product 

701 or process, and the like.‖

702 Emergency and standby power systems are essential for continuous operation of critical facilities, such as 

703 hospitals and emergency operations centers. Emergency and standby power are also needed to mitigate 

704 cascading failures of transportation and infrastructure systems that depend on electric power, including: 

705 communications networks, waste water lift stations, waste water treatment plants, water treatment plants, 

706 water distribution pumps, transportation fueling stations, traffic signals, traffic monitoring systems, and 

707 railway signals (ALA 2006).

708 Important considerations for safe and reliable operation of onsite emergency and standby power include:

709  Elevation of all electrical components, including generators, service panels, outlets, etc., above a 

710 design flood level that is appropriate to the importance/criticality of the facility

711  Proper ventilation of combustion products and cooling system components

712  Availability of adequate uninterruptable power supply (UPS) to support critical systems until 

713 emergency or standby power comes on line

714  Ability to start emergency or standby power 

715 generation without power from the grid 

716 (―black start capability‖)

717  Prioritization of power needs and proper 

718 sizing of generators and circuits to safely meet 

719 essential requirements

720  Installation of permanent quick-connect 

721 hookups to accept power from temporary 

722 generators and label the hook up with the 

723 power requirement to enable generator size 

724 selection

725  Ability to properly disconnect from the utility 

726 grid and to avoid feeding power back onto a 

727 de-energized grid (―islanding‖)

728  Ability to safely transfer back to the grid when primary power is restored

729 National Fire Protection Association Standards 110 and 111 provide performance standards for 

730 Emergency and Standby Power Systems (NFPA 2013a) and Stored Electrical Energy Emergency and 

731 Standby Power Systems (NFPA 2013b). NPFA 110 recognizes two classification levels: critical to life and 

732 safety (Level 1) and less critical (Level 2). Level 1 applications include life safety illumination, fire 

733 detection and alarm systems, elevators, fire pumps, public safety communications systems, industrial 

734 processes where current interruption would produce serious life safety or health hazards, and essential 

735 ventilating and smoke removal systems. Level 2 applications include heating and refrigerating systems, 

736 other communications systems, other ventilating and smoke removal systems, sewage disposal, lighting, 

737 and industrial processes.

738 Key considerations for emergency and standby power system fuels include:

739  Providing sufficient on-site fuel supply to support essential power loads until an ongoing supply 

740 of fuel can be safely and reliably delivered to the site

741  Selecting a fuel that is not dependent on electricity from the grid for delivery (e.g., pipe742 delivered, natural gas or truck-delivered liquid fuels such as diesel fuel)

743  Performing regular tests (at least monthly) and properly maintaining equipment

The US Army Corps of Engineers (USACE)

had developed tool called the Emergency 

Power Facility Assessment Tool (EPFAT). The 

EPFAT allows public entities to input 

generator and bill of material requirements into 

an on-line database with the intention of 

expediting the support of temporary power 

installations after events. There are currently 

over 16,000 facilities in the database. The 

EPFAT database may be accessed at 

http://epfat.swf.usace.army.mil/
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744 Alternative fuel sources, such as solar arrays with battery backups, can be considered as a means of 

745 maintaining lighting for emergency exit paths or providing water pressure in buildings or for operating 

746 transportation system signals or pumps at fueling stations (Andrews et al. 2013).

747 A partial listing of technologies used for generating emergency or standby power includes:

748  Diesel generators

749  Combined Heat and Power (CHP)

750  Microturbines

751  Reciprocating gas engines

752  Fuel cells

753 Diesel generators range from small mobile generators to larger permanently installed systems. Small

754 generators can be easily deployed to power traffic signals, rail crossing signals, or critical circuits in 

755 residential or small commercial buildings; but they require frequent refueling, pose safety hazards to 

756 inexperienced operators, and may not be reliable due to poor maintenance and infrequent use. Theft of 

757 generators is also a problem when left unattended to power transportation system signals, for example. 

758 Permanently installed generators may have more substantial fuel capacities and may be safer to operate 

759 and more reliable if tested and maintained on a regular schedule.

760 Following Superstorm Sandy, the State of New Jersey used FEMA HMGP funds to establish a Retail Fuel 

761 Station Energy Resiliency Program (NJOEM 2014). Eligibility requirements for the program include:

762  Stations must be located within 1⁄4-mile of an identified evacuation route

763  Stations with gasoline storage capacity of 30,000 to 35,000 gallons eligible for up to $15,000 

764 grant to purchase quick-connect technology or to offset a portion of the cost of purchasing a 

765 generator

766  Stations with gasoline storage capacity of more than 35,000 gallons eligible for up to $65,000 

767 grant toward the purchase and installation of an onsite generator

768  Stations must sell both gasoline and diesel fuel (except in limited instances)

769 The program requires a maintenance contract be in place for at least five years from the date of final 

770 approval of municipal building inspector. New Jersey’s Office of Homeland Security and Preparedness

771 (OHSP) was also selected by the federal DHS to conduct the Regional Resiliency Assessment Program 

772 (RRAP) on the State’s petroleum transportation and distribution system.

773 Combined Heat and Power (CHP) is a highly efficient method of providing uninterrupted power and 

774 thermal (heating or cooling) services to a host facility. CHP systems are typically powered by natural gas 

775 fueled turbines or reciprocating engines. Over a dozen case studies of successful CHP system 

776 performance during Superstorm Sandy and other recent large scale power outages have been documented 

777 by Hampson et al. (2013). Key advantages of CHP systems over conventional diesel generators include 

778 better reliability, lower fuel costs, lower emissions, and the ability to address thermal demands in addition

779 to power demands. Texas and Louisiana now require that all state and local government entities identify 

780 which government-owned buildings are critical in an emergency and that a feasibility study on CHP is

781 conducted prior to constructing or extensively renovating a critical government facility. In New York, the 

782 State Energy Research and Development Authority (NYSERDA) and the State Office of Emergency 

783 Management have partnered to educate emergency managers about the benefits of CHP systems in 

784 emergency facilities; and the governor has announced a $20 million investment towards CHP projects, 

785 with added incentives for projects serving critical infrastructure, including facilities of refuge (Hampson 

786 et al. 2013).

787 The technologies described in this section are mature and widely deployed. All of these technologies may

788 be employed and coupled with a sophisticated control system to support a microgrid. As noted earlier in 
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789 the emerging technologies section, microgrids can support normal or near-normal business operations

790 depending on the application and implementation of the system.

791 7.3. Performance Goals

792 Examples of Performance Goals at the community level were presented in Chapter 3 for different 

793 elements of critical infrastructure. This section presents an example of performance goals for the energy 

794 system components in fictional community Centerville, USA. Previous work to develop and establish 

795 performance goals or levels of performance is found in the efforts undertaken by SPUR (San Francisco), 

796 the California Energy Assurance Planning (CaLEAP) program, and Oregon. While these efforts were first 

797 developed at the local and state levels, respectively, they represent the most recent examples of major 

798 urban centers and an entire state developing a resilience plan to improve hazard resistance and 

799 infrastructure performance.

800 Table 7-3 through Table 7-5 represent example performance goals for the electrical subsystem for 

801 routine, expected, and extreme events (the three event levels of routine, expected, and extreme events 

802 were presented and discussed in Chapter 3 – the expected event is generally synonymous with a ―Design 

803 Level event‖ as defined by the relevant codes and standards.). This example is presented for the fictional 

804 community in and around Centerville, USA. Since the ability to provide services after a windstorm, ice 

805 storm, hurricane, or flood event allows a utility to win support from their customer base, many providers 

806 and entities for energy systems have been designing and rebuilding their infrastructure to consider more 

807 severe events to make their systems more resilient and reliable for their customers. As such, it is 

808 recognized that the 90% desired performance level is already at the existing or current performance level 

809 for most electric utilities in the example matrices. However, the target performance levels proposed may 

810 not currently be what are being achieved by all utilities and providers. 

811 The example performance goals presented in Table 7-3 through Table 7-5 are based on anticipated 

812 performance to support a community in a manner that is considered resilient, based on recent actual 

813 events and response times after storm and hazard events that have occurred over the past several years, 

814 and anecdotal reporting of response times. It is important to understand that a community may be 

815 different than the example community used in the performance goal tables. A community may have 

816 different infrastructure (for example, it may not have power generation or transmission assets, just 

817 distribution assets that must be evaluated and hardened for improved performance). Also, both the 

818 community stakeholders and the utilities supporting them will have different levels of expectation and 

819 actual performance (response to outages or interruptions) depending upon their geographic locations and 

820 past history of dealing with events of different magnitudes (routine, expected, or extreme). Further, much 

821 of the current infrastructure and response efforts managed by larger utilities may meet the 90% restored 

822 metric identified and therefore the blue shaded box can be marked with the ―X‖ and 90% are to show that 

823 they are ―overlapping.‖ The Centerville, USA example energy performance goals in this chapter do not 

824 show this scenario. However, the example performance goals for pipelines in Centerville, USA in Chapter 

825 6 so show this possibility. Again, an important and notable caveat to this is that Municipals and 

826 Cooperatives (Muni’s and Co-Ops) are not traditionally performing at this level and across the board they 

827 would likely be at least one box to the right of the current condition (X) mapped in the example matrix. 

828 It is also important to note that, for this system, there is a slight difference in the presentation of 

829 information related to percent of the system restored. The reality is that the percentage of the 

830 infrastructure the utilities desire to get back on line immediately will vary from community to community

831 and is focused on the sub element identified. If the performance goal is to have all Generation 

832 infrastructure operating and functional, but the reality is that the distribution sub elements may be 

833 damaged and not operational during the same time period, then each gets its own performance metric as 

834 shown (perhaps 90% (or 100%) for the generation, but only 30% of 60% for the other sub elements (such 

835 as transmission or distribution), and there may be further granularity in these sub elements based on the 

836 infrastructure in another community (see table). The sub elements presented and ranks here are a 
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837 representative set, communities may have a greater or smaller number of sub elements and functions than 

838 what has been depicted here. The local planning process should evaluate and establish the sub elements 

839 and functions for which the community and the industries should look to set performance goals.

840 Lastly, these performance goals will not capture or reflect the inability of the generation or transmission 

841 capabilities to be easily re-established when critical infrastructure assets are completely destroyed by an 

842 event (e.g., a surge that completely destroys a generation station or major transmission substation). Major 

843 impact events such as these are generally considered in that the grid will be able to respond and absorb 

844 some level of infrastructure failure. However in communities where there is a generation, transmission, or 

845 substation single-point-of-failure condition, that impact is not well-reflected in these metrics at this time.

846 Effort should be made to consider short- and long-term solutions to disruptions, outages, and 

847 interruptions. The ability of the sub elements and functions to be operational as soon as possible after an 

848 event can be achieved through a variety of solutions. Some may require capital investments, while others

849 are operational responses that are labor and personnel dependent. Some solutions will be dependent on 

850 technology or even completely dependent upon the resilience of other supporting systems. Additional 

851 information on codes, standards, and recovery levels for new and existing construction presented later in 

852 this section should be reviewed prior to completing a performance goals matrix for a community. 
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853 Table 7-3. Example Electrical System Performance Goals for Routine Event in Centerville, USA

Disturbance Restoration times

(1) Hazard Any (2) 30% Restored

Affected Area for Routine Event Localized 60% Restored

Disruption Level Minor 90% Restored

(3) X Current

854

Functional Category: Cluster

(4) 

Support 

Needed

(5) 

Target 

Goal

Overall Recovery Time for Hazard and Level Listed

Routine Hazard Level

Phase 1 – ShortTermPhase 2 --

Intermediate

Phase 3 – LongTerm

Days Wks Mos

0 1

1-

3

1-4 4-8 8-12 4 4-24 24+

Power - Electric Utilities

Generation 1

Critical Facilities and Infrastructure Systems R/C 90%

Emergency Housing and Support Systems R/C 90%

Housing and Neighborhood infrastructure R/C 90%

Community Recovery Infrastructure R/C 90%

Transmission (including Substations) 1

Critical Response Facilities and Support Systems

Hospitals, Police and Fire Stations / Emergency 

Operations Centers 90%

Disaster debris / recycling centers/ Related lifeline 

systems 90%

Emergency Housing and Support Systems

Public Shelters / Nursing Homes / Food

Distribution Centers 90%

Emergency shelter for response / recovery 

workforce/ Key Commercial and Finance 90%

Housing and Neighborhood infrastructure

Essential city services facilities / schools / Medical 

offices 90% X

Houses of worship/meditation/ exercise 90% X

Buildings/space for social services (e.g., child 

services) and prosecution activities 90% X

Community Recovery Infrastructure 

Commercial and industrial businesses / Nonemergency city services 90% X

Residential housing restoration 90% X

Distribution

Critical Response Facilities and Support Systems 1

Hospitals, Police and Fire Stations / Emergency 

Operations Centers 90% X

Disaster debris / recycling centers/ Related lifeline 

systems 90% X

Emergency Housing and Support Systems

Public Shelters / Nursing Homes / Food 

Distribution Centers 90% X

Emergency shelter for response / recovery 

workforce/ Key Commercial and Finance 90% X

Housing and Neighborhood infrastructure

Essential city services facilities / schools / Medical 

offices 90% X

Houses of worship/meditation/ exercise 90% X

Buildings/space for social services (e.g., child 

services) and prosecution activities 90% X

Community Recovery Infrastructure 

Commercial and industrial businesses / Nonemergency city services 90% X

Residential housing restoration 90% X

855 Footnotes:

1 Specify hazard being considered
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Specify level -- Routine, Expected, Extreme

Specify the size of the area affected - localized, community, regional

Specify severity of disruption - minor, moderate, severe

2 30% 60%

3 X Estimated restoration time for current conditions based on design standards and current inventory

Relates to each cluster or category and represents the level of restoration of service to that cluster or category

Listing for each category should represent the full range for the related clusters

Category recovery times will be shown on the Summary Matrix

"X" represents the recovery time anticipated to achieve a 90% recovery level for the current conditions

4 Indicate levels of support anticipated by plan

R Regional

S State

MS Multi-state

C Civil Corporate Citizenship 

5 Indicate minimum performance category for all new construction. 

See Section 3.2.6

856
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857 Table 7-4. Example Electrical System Performance Goals for Expected Event in Centerville, USA

Disturbance Restoration times

(1) Hazard Any (2) 30% Restored

Affected Area for Expected Event Community 60% Restored

Disruption Level Moderate 90% Restored

(3) X Current

858

Functional Category: Cluster

(4) 

Support 

Needed

(5) 

Target 

Goal

Overall Recovery Time for Hazard and Level Listed

Expected Hazard Level

Phase 1 – ShortTermPhase 2 --

Intermediate

Phase 3 – LongTerm

Days Wks Mos

0 1 1-3 1-4 4-8 8-12 4 4-24 24+

Power - Electric Utilities

Generation 1

Critical Facilities and Infrastructure Systems R/C 90% X

Emergency Housing and Support Systems R/C 90% X

Housing and Neighborhood infrastructure R/C 90% X

Community Recovery Infrastructure R/C 90% X

Transmission (including Substations) 1

Critical Response Facilities and Support Systems

Hospitals, Police and Fire Stations / Emergency 

Operations Centers 90% X

Disaster debris / recycling centers/ Related 

lifeline systems 60% 90% X

Emergency Housing and Support Systems

Public Shelters / Nursing Homes / Food 

Distribution Centers 60% 90% X

Emergency shelter for response / recovery 

workforce/ Key Commercial and Finance 60% 90% X

Housing and Neighborhood infrastructure

Essential city services facilities / schools / 

Medical offices 60% 90% X

Houses of worship/meditation/ exercise 60% 90% X

Buildings/space for social services (e.g., child 

services) and prosecution activities 60% 90% X

Community Recovery Infrastructure 

Commercial and industrial businesses / Nonemergency city services 60% 90% X

Residential housing restoration 60% 90% X

Distribution

Critical Response Facilities and Support Systems 1

Hospitals, Police and Fire Stations / Emergency 

Operations Centers 60% 90% X

Disaster debris / recycling centers/ Related 

lifeline systems 60% 90% X

Emergency Housing and Support Systems

Public Shelters / Nursing Homes / Food 

Distribution Centers 60% 90% X

Emergency shelter for response / recovery 

workforce/ Key Commercial and Finance 60% 90% X

Housing and Neighborhood infrastructure

Essential city services facilities / schools / 

Medical offices 60% 90% X

Houses of worship/meditation/ exercise 60% 90% X

Buildings/space for social services (e.g., child 

services) and prosecution activities 60% 90% X

Community Recovery Infrastructure 

Commercial and industrial businesses / Nonemergency city services 90% X

Residential housing restoration 90% X

859 Footnotes: See Table 7-3, page 22.
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860 Table 7-5. Example Electrical System Performance Goals for Extreme Event in Centerville, USA

Disturbance Restoration times

(1) Hazard Any (2) 30% Restored

Affected Area for Extreme Event Regional 60% Restored

Disruption Level Severe 90% Restored

(3) X Current

861

Functional Category: Cluster

(4) 

Support 

Needed

(5) 

Target 

Goal

Overall Recovery Time for Hazard and Level Listed

Extreme Hazard Level

Phase 1 – ShortTermPhase 2 --

Intermediate

Phase 3 – LongTerm

Days Wks Mos

0 1 1-3 1-4 4-8 8-12 4 4-36 36+

Power - Electric Utilities

Generation 1

Critical Facilities and Infrastructure Systems R/C 90% X

Emergency Housing and Support Systems R/C 90% X

Housing and Neighborhood infrastructure R/C 90% X

Community Recovery Infrastructure R/C 90% X

Transmission (including Substations) 1

Critical Response Facilities and Support Systems

Hospitals, Police and Fire Stations / Emergency 

Operations Centers 60% 90% X

Disaster debris / recycling centers/ Related lifeline 

systems 60% 90% X

Emergency Housing and Support Systems

Public Shelters / Nursing Homes / Food Distribution 

Centers 60% 90% X

Emergency shelter for response / recovery workforce/ 

Key Commercial and Finance 60% 90% X

Housing and Neighborhood infrastructure

Essential city services facilities / schools / Medical 

offices 60% 90%

Houses of worship/meditation/ exercise 60% 90%

Buildings/space for social services (e.g., child 

services) and prosecution activities 60% 90%

Community Recovery Infrastructure 

Commercial and industrial businesses / Nonemergency city services 60% 90%

Residential housing restoration 60% 90%

Distribution

Critical Response Facilities and Support Systems 1

Hospitals, Police and Fire Stations / Emergency 

Operations Centers 60% 90%

Disaster debris / recycling centers/ Related lifeline 

systems 60% 90%

Emergency Housing and Support Systems

Public Shelters / Nursing Homes / Food Distribution 

Centers 60% 90%

Emergency shelter for response / recovery workforce/ 

Key Commercial and Finance 60% 90%

Housing and Neighborhood infrastructure

Essential city services facilities / schools / Medical 

offices 60% 90% X

Houses of worship/meditation/ exercise 60% 90% X

Buildings/space for social services (e.g., child 

services) and prosecution activities 60% 90% X

Community Recovery Infrastructure 

Commercial and industrial businesses / Nonemergency city services 60% 90% X

Residential housing restoration 60% 90% X

862 Footnotes: See Table 7-3, page 22.
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863 7.4. Regulatory Environment

864 The electric utility and liquid fuel industries are highly regulated with the goal of keeping prices low, 

865 keeping delivery safe, and providing reliable, quality products to consumers. Regulation occurs at the 

866 federal and state levels.

867 The Federal Energy Regulatory Commission (FERC) is the US national regulatory body responsible for 

868 interstate transmission of oil, natural gas, and electricity. They are also responsible for reviewing 

869 interstate gas pipeline proposals, licensing hydropower plants, and reviewing proposals for developing 

870 liquefied natural gas terminals. FERC regulates the interstate wholesale sales and transmission of 

871 electricity, reviews and makes decisions on utility mergers and acquisitions, monitors and investigates 

872 energy markets, and provides rulings on transmission siting applications. FERC has the authority to 

873 provide civil penalties and fines for non-compliance to regulatory rules.

874 The Western Energy Crisis, the Enron scandal, and a historic East Coast blackout, led Congress to grant 

875 broad new authority to the FERC in 2005. After this third event, the Northeast Blackout, a joint US876 Canada task force studied the causes and effects of the 2003 blackout and identified the need to make 

877 reliability standards mandatory and enforceable with penalties for noncompliance. So, in the Energy 

878 Policy Act of 2005 - Public Law 109-58 - (EPAct 2005), Congress entrusted FERC with a major new 

879 responsibility to oversee mandatory, enforceable reliability standards for the nation’s Bulk Power 

880 System—that is, the wholesale power grid. The importance of this change cannot be overstated. The 

881 business of reliability became not just a set of industry best practices; it became a matter of national 

882 importance. 

883 Through Section 215 of the Federal Power Act, Congress authorized FERC to certify a national electric 

884 reliability organization. That ERO is the North American Electric Reliability Corporation (NERC). NERC 

885 is a not-for-profit entity whose mission is to ensure the reliability of the Bulk Power System (BPS) in 

886 North America. This means that it is the responsibility of NERC to develop and enforce Reliability 

887 Standards. Further, they are to annually assess seasonal and long-term reliability, monitor the BPS

888 through system awareness, and educate, train, and certify industry personnel. 

889 Each state has a regulatory commission whose responsibility is to represent the electricity consumers in 

890 their jurisdiction. State commissions regulate retail electricity and gas, approve physical construction of 

891 infrastructure projects, provide rulings on local distribution of electricity and gas, and provide general 

892 regulatory oversight of local utilities and gas distribution companies. The commission meets regularly 

893 with state utilities and performs performance assessments. If performance metrics are not met, utilities 

894 may be punished or fined.

895 7.4.1. Federal 

896 At the federal level there is regulation by FERC which is ―an independent agency that regulates the 

897 interstate transmission of electricity, natural gas, and oil.‖ FERC does not have siting authority for electric 

898 transmission facilities, but it does regulate reliability standards through NERC.

899 NERC is also at the federal level which, as defined, is ―a not-for-profit international regulatory authority 

900 whose mission is to ensure the reliability of the bulk power system in North America. NERC develops 

901 and enforces Reliability Standards; annually assesses seasonal and long‐term reliability; monitors the bulk 

902 power system through system awareness; and educates, trains, and certifies industry personnel. NERC’s 

903 area of responsibility spans the continental United States, Canada, and the northern portion of Baja 

904 California, Mexico. NERC is the electric reliability organization for North America, subject to oversight 

905 by the Federal Energy Regulatory Commission and governmental authorities in Canada.‖

906 The Nuclear Regulatory Commission (NRC), another federal regulator, focuses primarily on nuclear 

907 power plants. The NRC is responsible for licensing and inspecting nuclear reactors, and providing 

908 regulations, guidelines, and best practices for their operation. They are also responsible for any nuclear 
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909 fuel manufacturing oversight and for coordinating and participating in nuclear energy research and 

910 development.

911 Each of the various state and federal authorities regulates different and overlapping aspects of the electric 

912 system. The requirements, standards and codes for each are lengthy and complex and are ever evolving 

913 but it is these that must form the basis for future refinements to facilitate reliability and preparedness 

914 improvements.

915 7.4.2. State 

916 The utilities are constantly in a complex regulatory dance with state public service commissions,

917 regarding the rapidly changing rules governing their roles and responsibilities. Recently, one of the 

918 biggest issues for utilities and commercial generators, particularly rooftop solar companies, involves the 

919 regulation of ―behind the meter‖ load (such as rooftop solar) and their ability to sell power back into the 

920 grid to the utility. This is referred to as ―net metering‖ and, again, the rules vary from state to state. The 

921 concern from utilities is that they remain responsible for upgrade and maintenance of a grid 

922 interconnection system that would receive less revenue and would also need to handle the varying bi923 directional load demands that can add complexity to an already stressed infrastructure.

924 Although the push to lower greenhouse gas emissions and increase self-reliance using on-site methods,

925 such as roof-top solar (and potentially storage), has merit, so does improving the backbone and efficiency 

926 of our electric grid. Grid improvements can also dramatically reduce line loss, thereby increasing 

927 environmental benefits and reliability; but those improvements are expensive and require significant

928 investment. The debate is escalating as additional unique and beneficial ―generation‖ and ―virtual 

929 generation‖ options arise.

930 This push-pull is being played out right now in the headlines and before state public service commissions 

931 (PSCs) and utilities across the country. It is therefore imperative that these evolving rules of conduct be 

932 formulated with an eye to cost, reliability, safety, disaster preparedness and environmental benefit. The 

933 rules themselves will be primarily administered by state PSCs and utilities; but the oversight roles of the 

934 regional Independent System Operators (ISOs) and the Regional Transmission Organizations (RTOs) is 

935 also key, particularly with respect to cost and reliability.

936 The ISOs and RTOs serve much the same function, though the RTOs have greater responsibility for their 

937 regional transmission network as established by FERC. However, both the ISOs and RTOs operate 

938 regional electricity grids, administer the wholesale electricity markets, and provide reliability planning for 

939 the bulk electric system. Some of these systems such as the New York ISO (NYISO) are single state 

940 systems, and some are more regional such as the ISO New England (ISO-NE) system and the Southwest 

941 Power Pool (SPP). Due to the inter-relatedness of the North American grid, the ISO/RTO systems are 

942 international and include for example, the Alberta Electric System Operator.

943 7.4.3. Local 

944 At the State and Local levels, codes and standards are adopted by the State PSCs, PUCs, ISOs, and RTOs 

945 to govern design and construction of the infrastructure. There is a wide variation in the level of design 

946 guidance that is provided by the codes and standards adopted by these entities. While some have best947 practices, others reference ANSI-approved, consensus codes and standards. But even when the codes and 

948 standards are adopted, there is an apparent lag in adopting the most current version of these standards. 

949 7.5. Codes and Standards

950 A number of codes and standards are used in the power industry for design and construction of 

951 generation, transmission, stations/substations, and distribution assets. While ASCE 7 (mentioned earlier 

952 in this document) is now incorporated by reference and used more frequently than in the past, most of the 

953 Transmission and Distribution assets are designed to the National Electric Safety Code (NESC) or the 

954 Rural Utilities Service (RUS), respectively. There are many variables related to design and construction 
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955 of these assets. As such, not all elements may be addressed here or will require additional cross checking 

956 with additional codes, standards, and regulations.

957 In 2009, NIST established the Smart Grid Interoperability Panel (SGIP). The SGIP is a private-public 

958 partnership that identifies electricity delivery standards gaps, fills the gaps through requirements analysis, 

959 and coordinates with Standards Setting Organizations (SSOs) to create or modify interoperability 

960 standards and guidelines. The SGIP maintains a Catalog of Standards (CoS) that lists many standards that 

961 have been vetted through a regimented process with regards to cybersecurity and architectural integrity.

962 The electric code that is adhered to by the Investor-Owned Utilities (IOUs), who design and construct the 

963 Transmission assets, is the National Electric Safety Code (NESC); Sections 24 (Grades of Construction), 

964 25 (Loading Requirements) and 26 (Strength Requirements). NESC Rules 215 (grounding) and 218 

965 (trees) present information important to vegetation management. While this is truly a safety code, it is 

966 used as a design code in lieu of other guidance. Each utility also has a Standards department that 

967 evaluates the various codes and standards (safety or design) that are applied during design and 

968 construction of their assets. They evaluate any new equipment to ensure it meets or exceeds these 

969 standards. From the baseline set forth in the NESC, it is important to note that all IOUs have developed 

970 their own standards for their respective systems. While most of these standards exceed the minimums set 

971 forth by the NESC, the question that exists is whether the baseline set forth in the NESC addresses the 

972 performance desired for resiliency when considering all hazards (flood, wind, seismic, ice, and other 

973 natural hazards and man-made threats). 

974 In a similar fashion, but working from a different set of criteria, the Co-operatives and Municipalities 

975 responsible for Distribution assets use the design manuals/standards from the Rural Utilities Service 

976 (RUS). The RUS distribution line design manuals consist of RUS bulletins 1724-150 through 1724-154. 

977 These refer to the identification of critical loads/customers and poles/equipment. In all cases, each utility 

978 is applying more constringent wind and ice loading conditions from these codes.

979 The information in the following subsections is provided to help communities better develop their own 

980 performance metrics for new (or recent) construction by identifying some of the performance criteria that 

981 was likely considered in the design of these assets.

982 7.5.1. New Construction

983 For some elements of the energy system, the design criteria for hazards have been aligned with building 

984 standards such as ASCE 7 Minimum Design Loads for Buildings and Other Structures. However,

985 performance goals for these systems for each event are less defined. Definitions are also less clear 

986 regarding what are considered ―routine,‖ ―expected,‖ ―extreme,‖ or ―catastrophic‖ events. As resilience 

987 becomes better defined, this framework is working to bring together different interpretations and 

988 definition of these events as they are defined and used in practice within the existing industries and 

989 codes/standards used in each industry. 

990 The following is a summary of hazards considered by the NESC (Part 2, Section 25):

991  250B – Combined Ice and Wind – This is the basic loading criteria and is known as the District 

992 Loading. It incorporates both wind and ice with overload and strength factors. This applies to all 

993 structures and references the map presented in Figure 250-1. The boundaries of the districts 

994 follow county lines. Data was obtained from a small number of weather stations which were far 

995 apart. While the industry has discussed replacing this map with appropriate maps from ASCE 7, 

996 this issue is still being evaluated. 

997  250C – Extreme Wind – These criteria account for the higher winds typically found along the 

998 coastline and during extreme events. These criteria are only used for structures that are higher 

999 than 60’ above ground (70’ pole and longer). Appropriate maps are Figures 250-2a through 250-

1000 2e. Due to their typical tower height, transmission lines are designed to these criteria. The 

1001 overload and strength factors used are generally 1 since this is an extreme event map (note, the 
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1002 nomenclature of ―extreme wind‖ used here is not consistent with the extreme wind event used for 

1003 the design and construction of buildings or storm shelters per the ICC-500 Standard for the 

1004 Design and Construction of Storm Shelters). These criteria were first introduced into the NESC in 

1005 1977. The 2002 NESC incorporated the wind maps from ASCE 7-98; where the wind data was 

1006 much more comprehensive. The 2012 NESC uses the wind maps from ASCE 7-05. The ASCE 7-

1007 10 wind maps were revised to better represent the wind hazard. The maps now are based on new 

1008 modeling efforts, refinements to understanding of wind performance, and incorporation of the 

1009 contribution of the Importance Factor [I] into the data presented by the maps. However, these 

1010 maps are currently not used by the NESC based on a decision by their code committee to retain 

1011 the use of the ASCE 7-05 wind maps.

1012 Most distribution structures are lower than the 60 ft. height limitation; therefore, most utilities will not 

1013 design their distribution lines to the ASCE 7 criteria (something that may need to be reconsidered 

1014 depending upon performance of these systems during hurricanes and tornadoes over the past 2 decades).

1015  250D – Combined Ice and Wind – This criterion was added in the 2007 NESC to account for 

1016 extreme ice events. This criterion is similar to the Extreme Wind loading. Most Transmission 

1017 assets will be designed to this criterion while distribution assets will not. Over the years most 

1018 utilities had their own extreme ice loading for the design of Transmission assets. The maps from 

1019 ASCE 7-05 have been retained and referenced for this criterion.

1020  Additional Standards related to hazard-resistant design include:

1021  ASCE 7-10 exempts electrical lines from seismic design

1022  ASCE 113 applies design criteria for stations. Seismic design is addressed in this standard

1023  ANSI O5 applies to wood poles

1024  ANSI C29 applies to insulators

1025 Some utilities on the east coast are now starting to look at station hardening due to hurricane Sandy. This 

1026 includes raising structures and control buildings at existing stations, or relocating the station outside the 

1027 flood zone. Much of this guidance is a result of state and local floodplain management practices and 

1028 requirements as opposed to specific codes, standards, or regulations from the energy industry itself. And 

1029 while NSEC rules exist for vegetation management, there is a lack of Codes, Standards, and industry1030 accepted Best Management Practices that consistently address maintenance requirements.

1031 7.5.1.1. Implied or stated Performance Levels for Expected Hazard Level

1032 As discussed in the previous section, structures greater than 60 feet tall are designed for ASCE 7 wind 

1033 and ice hazards. Though the NESC defines these as an ―extreme‖ loading case, these loads are consistent 

1034 with the expected event as defined in this framework. Therefore, new/future energy infrastructure greater 

1035 than 60 feet tall should experience very few failures in an expected event. However, energy infrastructure 

1036 less than 60 feet tall (i.e., most distribution structures) is not required to be designed to the NESC 

1037 ―extreme‖ loads. Rather, they are designed to Rule 250B criteria, which is less than an expected event as 

1038 defined in Chapter 3. Therefore, failures in the energy distribution system are likely to occur in an 

1039 expected ice or wind event. As seen in the example performance goals in Section 7.3, it is anticipated that 

1040 some failures in the distribution system would also occur to the routine wind or ice event, though these 

1041 will likely be limited, resulting in less outages. 

1042 Many failures of the energy infrastructure are due to tree fall or debris impact rather than direct wind/ice 

1043 loading itself. Therefore, the electric utility’s ability to maintain an effective tree-trimming program will 

1044 greatly impact the performance levels of the infrastructure when a hazard event does occur.

1045 7.5.1.2. Recovery levels

1046 As discussed, failures of energy infrastructure less than 60 feet are likely to occur in an expected event, 

1047 particularly wind and ice events. The time to recover and restore service so the system is fully functional 
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1048 will depend on a number of factors, such as whether distribution lines are overhead or underground, 

1049 effectiveness of the energy utility tree-trimming program, mobility of emergency repair crews, 

1050 availability of resources for repair, and size of the impacted area. Overhead distribution lines may fail 

1051 more frequently due to wind or ice events. However, these failures are easier to access and repair than 

1052 underground lines, which may occur due to other events. 

1053 For earthquakes, overhead structures would be anticipated to perform well due to their flexibility. 

1054 However, buried distribution lines may fail due to liquefaction or if there is not enough slack in the lines 

1055 to resist the forces from earthquakes. Flooding may also lead to failure of underground infrastructure if 

1056 not adequately protected. As previously stated, underground infrastructure damage is more difficult to 

1057 access and fix. Therefore, while overhead distribution infrastructure may have more widespread failures, 

1058 it will only take days to weeks to recover, whereas only a few underground failures may result in the same 

1059 recovery time. However, widespread underground failures may result in weeks (rather than days) of 

1060 recovery time to achieve full functionality of the system. 

1061 7.5.2. Existing Construction

1062 For the older infrastructure elements of the energy system, the design criteria used for hazards varies 

1063 greatly. In many cases, little to no consideration was given to the forces and loads imparted onto this 

1064 infrastructure because the infrastructure pre-dated the modern codes such as ASCE 7 Minimum Design 

1065 Loads for Buildings and Other Structures that provide criteria to calculate and apply such loads. In some 

1066 instances, most hazard resistance was incorporated through anecdotal information such as siting of critical 

1067 infrastructure based on past-historical storms or it was provided through conservative design approaches 

1068 and uses of materials that, by their nature, happen to provide some level of resilience. Further, 

1069 performance goals for these systems were likely never considered or defined. As a result, old 

1070 infrastructure has inherent vulnerabilities because many of the systems were not designed for these 

1071 specific hazard loads. This section discusses the anticipated or implied performance from existing 

1072 infrastructure elements to help develop better performance metrics for communities. 

1073 Existing infrastructure in the energy system was designed and constructed to codes and standards that did 

1074 not address hazards to the level of current codes and standards. Because of this a number of 

1075 vulnerabilities exist in both the electrical system, and the communications infrastructure used to control it. 

1076 As a result, these older assets remain vulnerable (with existing equipment and systems) unless the 

1077 equipment is replaced due to age or new codes/regulations or enforced internal utility best practices 

1078 require an upgrade. Examples of these vulnerabilities are:

1079  Clustered, below grade transformers. Transformers tightly clustered in underground vaults and 

1080 small substation yards – many at or below grade (to hide the ugly infrastructure). These below 

1081 grade vaults often fill with water and debris during floods, mud slides, and earthquakes.

1082 Redundant means must be provided to mitigate these hazards to enjoy the otherwise substantial 

1083 benefit of below grade, protected infrastructure.

1084  Single pole substation high and low voltage feeds. Using single poles to take both the incoming 

1085 and outgoing lines from substations add a potential single point of failure. If separated and the 

1086 incoming high voltage pole/tower fails, distributed generation may still be able to feed the station.

1087 If a low side feeder exit pole fails, the incoming high voltage feed remains as do other low 

1088 voltage feeder poles.

1089  Fuses, not breakers in many locations. Using fuses rather than breakers/reclosers in different 

1090 parts of a distribution system is cost based. Using more breakers and reclosers may be a new best 

1091 practice when considering resiliency. Also, the lack of sectionalizers in many utility systems can 

1092 mean that a single fault prevents all customers from having power turned back on while the 

1093 damaged circuit is being repaired.

1094  Underground ducts run close together and crossing in many shallow manholes. A potential

1095 common mode failure challenge not generally considered in existing design practices.
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1096  Lack of automation. Most switching in the distribution grid today is local and manual – meaning 

1097 that to turn on power using alternate configurations, a person has to get to the gear when staff to 

1098 do that is the most scarce.

1099 Other vulnerabilities present in existing communications and control equipment include supporting the 

1100 energy system:

1101  Single communications card/frequency in devices. Single point of failure issue and potential 

1102 interference issue with increased radio traffic used in major disaster response scenarios.

1103  Single encryption key or worse (default passwords) for all devices in a system. This is a well1104 known security issue being addressed in critical infrastructure – but presently most distribution 

1105 systems are not considered critical infrastructure.

1106  Very small batteries/super capacitors in devices. This leads to very short communications 

1107 windows – on narrow channels – which progresses to notable numbers of dropped or missed 

1108 communications during outages limiting the ability to optimize crew dispatch.

1109  Mesh networks performance on cold start. Some mesh network implementations being used for 

1110 field area networks tend to be very fragile when the system starts to have outages, and take time 

1111 to reform after an outage – while the mesh design is supposed to be highly resilient in the most 

1112 critical moments – it can be its own worst enemy as implemented today (e.g. small batteries, deep 

1113 mesh designs, lack of stored cold start parameters, etc.)

1114  Common right of ways. Fiber and other communication circuits tend to run in the same rights of 

1115 ways (on the same poles) as the electrical service – breaking one normally breaks both. 

1116  Telecommunications Route Diversity. This concept is often a myth because of the small number 

1117 of telecomm switches/and actual central offices/as well as multiplexing thousands of VPNs in a 

1118 single fiber

1119  Cellular Communications Emergency Operating Practices. While cellular towers offer dual 

1120 coverage in many places, the tendency is to only put batteries at some and back up generation at 

1121 fewer locations – so the towers revert to emergency calling only when the grid goes down –

1122 locking out grid communications that use cellular communications for backhaul.

1123  Digital Phone System Powering Requirements. Unlike the POTS system – the new digital phone 

1124 systems requires power at each street box – in some cases there are batteries, in others there are 

1125 not – Cable companies have the lowest installation of batteries in their VOIP = data systems 

1126 compared to other telecomm providers

1127  Wireless Communications Spectrum Clustering and Frequency Agility. Wireless frequencies 

1128 tend to be highly clustered, meaning that even low power jammers can disrupt all of the wireless 

1129 related communications to the grid (e.g. Push to talk and DA/SA/AMI, etc.)

1130  Signaling System Security Vulnerabilities. SS7 vulnerabilities have not been closed for G3 or 

1131 G4 cellular systems – meaning that they can be jammed or intercepted by a knowledgeable 

1132 person with little in the way of specialized equipment in an unencrypted form.

1133 Most of these issues do not have explicit codes and regulations – but some do. Most come under 

1134 the category of best practices on both customer and utility sides of the meter. These 

1135 vulnerabilities will remain until new construction undertaken using new codes and best practices 

1136 that consider resilience replaces the older infrastructure.

1137 7.5.2.1. Implied or stated Performance Levels for Expected Hazard Level

1138 Some existing utility infrastructure is up to 30 years in age and most infrastructure 10 years or newer are 

1139 highly dependent on communications and control networks to operate effectively in adverse conditions.

1140 This is especially true for those systems with some level of automation that permit automatic or remote 

1141 controlled circuit switching, sectionalizing and reconfiguration. Situational awareness to know the 

1142 availability and operational state of field assets is also directly impacted by the availability of 

1143 communications equipment.
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1144 There are multiple failure modes for communications and control equipment. One that is addressed by 

1145 codes and standards for new construction is the ability of this electronic equipment to operate correctly in 

1146 harsh environmental conditions. Early implementations of network gear in substations were based on 

1147 consumer gear (think LinkSys) that had very low tolerance for temperature, humidity, shock, vibration,

1148 and the electromagnetic environment. Even first generation industrial quality gear intended for utility 

1149 applications did not consider the environment found in substation and feeder applications. New standards,

1150 such IEC 61850-3 and IEEE 1613, begin to address these concerns. The IEC standard used around the 

1151 world, but especially in Europe, have good environmental (temperature, shock, and vibration) guidelines 

1152 – but the equivalent IEEE standard used primarily in North America does not. In North America there is 

1153 presently no code or regulation that requires communications and control equipment to comply with any 

1154 standard – and utility enforced best practices are still emerging. The bottom line is that the system will be 

1155 vulnerable to communications and control failures in extreme conditions for some time to come.

1156 7.5.2.2. Recovery levels

1157 When events do occur and recovery efforts are required, the priorities and restoration efforts should 

1158 address emergency-related societal needs first and progress through a tiered response. While the model of 

1159 recovery can be complex, for simplicity, three general tiers to focus on are the restoration of services for 

1160 emergency facilities and services (Critical and Essential Facilities), for critical public works and right of 

1161 way (access) for critical infrastructure restoration crews, and then the systematic restoration of the 

1162 community at large. Samples of how the infrastructure elements may (and could) perform was discussed 

1163 in Section 7.3. Additional suggestions for how the infrastructure and facilities should respond when 

1164 impacted by a Routine, Expected, or Extreme event are also expanded upon below:

1165 1. Emergency Facilities and Services Restoration: Technologies and systems that address core 

1166 emergency services should be properly planned, tested, maintained, and restored first. These 

1167 facilities normally include 911 call centers, police, fire, and emergency medical dispatch stations.

1168 They also include centers identified for emergency shelter, food, and water, such as community 

1169 centers, schools, and stadiums. When planning for disaster responsiveness, also consider 

1170 communication infrastructure that links critical emergency resources (wire line communications, 

1171 cellular radio, and third party managed radio systems).

1172 2. Critical Rights of Way and Infrastructure Restoration: The next priorities to address include 

1173 systems necessary to dispatch and manage road and right of way clearing crews, electric repair 

1174 crews, and other non-emergency yet vital restoration related organizations and services. This list

1175 includes critical government facilities and communications paths to allow government to function 

1176 effectively, manage the crisis, and maintain civil order. Energy resiliency in this sense covers 

1177 emergency power for utility crew dispatch centers, key city buildings such as city hall, public 

1178 works crew facilities. It also covers the business processes in place to ensure generators and UPS 

1179 systems in these facilities are sized appropriately and tested periodically.

1180 3. Socio-Economic Continuity Restoration: The next priority is to support socio-economic 

1181 continuity. Full restoration typically requires days or even weeks. This aspect of restoration is 

1182 often unplanned and the biggest utility clients or loudest complainers often move to top of the 

1183 priority list. This element should be carefully prioritized and integrated into a community 

1184 resilience plan. First, ensure citizens outside of the community shelters have access to food, 

1185 water, fuel/energy, and communications. After these immediate needs are met, identify 

1186 businesses supporting the basic needs of citizens such as water and sewage utilities, grocery 

1187 stores, gas stations, drug stores, internet and telephone service providers, and make them 

1188 priorities for restoration.

1189 4. Mitigation projects or resiliency efforts may include hardening distribution systems and 

1190 employing technologies such as backup generation, renewable energy, or microgrids to ensure 

1191 these facilities remain online throughout the event or can be rapidly restored. Key infrastructure 
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1192 elements also need protecting, such as sewage lift stations and water pumping stations. All these 

1193 equipment and systems should be periodically tested and properly maintained in order to achieve 

1194 the economic and societal benefit of the investment.

1195 7.6. Strategies for Implementation of Community Resilience Plans

1196 Section 7.2 discusses components of the energy infrastructure system. The discussion includes some 

1197 potential vulnerabilities observed in the past encouraging the reader to think about the different hazards 

1198 that could impact the energy infrastructure in their community. The number, types, and magnitudes of 

1199 hazards that need to be considered will vary from community to community. 

1200 Section 7.3 discusses the performance goals of the energy infrastructure strived for by the community. 

1201 Section 7.3 does provide example performance goals for the routine, expected and extreme event. 

1202 However, the performance goals should be adjusted by the community based on its social needs.

1203 Sections 0 and 7.5 outline some of the regulatory levels and issues, and codes and standards that the 

1204 reader should keep in mind when planning to make upgrades/changes to existing energy infrastructure. 

1205 The objectives of this section are to use the information from Section 7.2 through 7.5 and provide 

1206 guidance on how a community should work through the process of assessing their energy infrastructure, 

1207 define strategies to make its infrastructure more resilient, and narrow the resilience gaps.

1208 7.6.1. Available Guidance

1209 Another term is often used to describe energy system resiliency and reliability – Energy Assurance. 

1210 Energy Assurance refers to the entire process of managing all aspects of energy delivery, resiliency and 

1211 reliability to ensure a desired outcome for how energy services will perform during normal and abnormal 

1212 situations.

1213 Energy Assurance is often focused on assisting local governments to become more resilient to loss of 

1214 energy. Becoming more energy resilient will help local governments prepare for, respond to, recover 

1215 from, and mitigate against potential emergencies that impact energy while minimizing economic loss and 

1216 protecting public health and safety. For the purposes of this framework, Energy Assurance is about: 

1217  Ensuring ―key assets‖ are functional when needed; 

1218  Fostering critical public-private partnerships before incidents happen; 

1219  Gaining awareness of energy dependencies; and, 

1220  Identifying actions and projects to move toward increased energy resiliency.

1221 Examples of how Energy Assurance is used as a means to collect the multitude of disciplines, 

1222 characteristics and dimensions of energy delivery, resilience, and reliability planning processes together 

1223 include the DOE’s Energy Assurance program (http://energy.gov/oe/services/energy-assurance), The 

1224 National Association of State Energy Officials (NASEO) State Energy Assurance Guidelines 

1225 (http://www.naseo.org/Data/Sites/1/documents/publications/State_Energy_Assurance_Guidelines_Versio

1226 n_3.1.pdf), and the California Local Energy Assurance Planning (CaLEAP) process 

1227 (http://www.caleap.org).

1228 Energy Assurance, as a whole, is about assuring that essential services are maintained in the event of an 

1229 energy disruption. The first step is to identify the ―key assets‖ of the essential services in the community 

1230 and determine their vulnerabilities. The key assets could be as big as an entire building (e.g., Police or 

1231 Fire Station) or as small as an element within a building (e.g., communications or HVAC system). 

1232 Building relationships is another part of Energy Assurance. Many emergency managers know that 

1233 building partnerships after a disaster is too late. Attempting to identify who to reach and working around 

1234 potential obstacles to reach them (e.g., limited or down telecommunications) is difficult. Establishing 

1235 these relationships helps local governments anticipate actions and clarify roles and responsibilities prior 

1236 to events; thus increasing the likelihood of a successful and efficient response and recovery. 
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1237 Gaining an awareness and/or understanding of energy interdependencies is also a very important piece of 

1238 energy assurance. Our communities have become very complex and many elements within them rely 

1239 upon another element within the community. In some instances, water systems need energy for their 

1240 services, but energy providers also need water to produce energy. Understanding these relationships is 

1241 vital in decision making. 

1242 With a good understanding of the key assets and interdependencies, a local government, working with the 

1243 local energy provider, can identify actions and projects to become more energy resilient.

1244 Because resilience is new, there is a significant need for tools to help both the community and the 

1245 industry assess resilience. Tools and methods exist to measure reliability, but again, these calculated 

1246 values typically look at systems during blue sky events and not during natural hazard events.

1247 An example of how resilience has been addressed during recent initiatives is found in energy assurance 

1248 planning programs. A first step toward implementing resilience in the energy industry is to develop an 

1249 Energy Assurance Plan tailored for a community. The flowchart developed by the CaLEAP program 

1250 illustrates the overall approach for developing such a plan including forming an EAP team. Notice that 

1251 this flowchart is similar to that shown in Chapter 3 of this document outlining the approach to achieve 

1252 community resilience.

1253

1254 Figure 7-3: Energy Assurance Flowchart Developed by CaLEAP

1255 Thinking about resilience as an aspect of reliability might be the quickest means to develop assessment 

1256 methodologies to assess and score resilience – especially from the energy service provider perspective. It 

1257 may allow the ability to explicitly consider large-scale events and non-traditional hazards that were 

1258 sometimes neglected in previous assessments. It would also set up a means to consider resilience in the 

1259 current industry mode that allows for variable pricing for duration and a better understanding of scale by 

1260 adapting to risk-based frameworks that capture interdependencies and likelihood. By assimilating 

1261 resilience into the factors that assure reliability, regulators might not be charged with setting new criteria 

1262 for utility performance.

1263 The length of time to restore electric service is a traditional metric of grid reliability. Similarly, the grid’s 

1264 ability to ride through minor disturbances or avoid cascading outages is already considered within 

1265 existing grid reliability indices. While these metrics and indices (such as System Average Interruption 
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1266 Duration Index [SAIDI], the Customer Average Interruption Duration Index [CAIDI], the System 

1267 Average Interruption Frequency Index [SAIFI], the Customer Average Interruption Frequency Index 

1268 [CAIFI], and others) exist, there are limitations to how these apply to the grid, including the fact that most 

1269 reliability indices and metrics are blue-sky indicators. When looking at and defining resilience, the events 

1270 that cause us to measure and evaluate the performance of the grid take place in much harsher and 

1271 significant conditions (such as natural hazard events and acts of vandalism, crime, and terrorism).

1272 Performance goals tables, such as those in Section 7.3, can be used by communities and energy utility 

1273 providers to set goals for recovery times during hazard events. However, these tables can also be used 

1274 define to determine the anticipated performance of the infrastructure (i.e., the ―X‖ in the performance 

1275 goals tables) for a given event. The community or utility can then define the resilience gaps (i.e., the 

1276 difference between the ―90%‖ and ―X‖ in the performance goals tables) and prioritize strategies for 

1277 enhancing the resilience of the energy infrastructure system. 

1278 7.6.2. Strategies for new/future Construction

1279 In general, when identifying equipment, and other components within the energy system, one of the 

1280 qualifying criterion should focus on resiliency. When evaluating different vendors and system 

1281 components, check their track record and references, and collaborate with others.

1282 Construction Strategies. There are several construction strategies that can be used to help improve 

1283 resilience of energy infrastructure from hazard events, including the following: 

1284  Strengthening and reinforcing critical lines leading to population centers or other critical loads. 

1285 For instance, adding line reinforcements to lines that serve a hospital or fire station makes them 

1286 more resilient to wind, ice, and branch loads.

1287  Establish pole depth standards based on local soil conditions for each pole height. Ensure that 

1288 poles are planted to the correct depth and the foundation will support the loads.

1289  Do not overload poles.

1290  Consider using National Electrical Safety Code (NESC) Grade B construction standards for 

1291 critical distribution lines. This grade of construction is commonly used in the utility industry and 

1292 utility surveys show that using Grade B for storm hardening is a popular and effective resiliency 

1293 construction strategy.

1294  Consider undergrounding. There are definite pros and cons to using undergrounding. They are 

1295 less vulnerable to weather, fire, and man-made hazards, but certainly not earthquakes. It is 

1296 expensive and when faults do occur, they are difficult to locate, take much longer to get to, and 

1297 are expensive to fix. For an event like Hurricane Sandy or the ice storms of 2012 and 2013, 

1298 underground cables would have dramatically reduced the amount of damage and restoration 

1299 times. For an earthquake in California, it could have the opposite effect. Due to the increased 

1300 costs associated with undergrounding, some options include:

1301  Underground circuits based on the largest number of customers services.

1302  If there are circuits that will be difficult to access (especially during weather-related hazard 

1303 events), underground those circuits.

1304  If there are circuits whose terrain and surrounding environment make it relatively easy and 

1305 inexpensive to install underground cable, underground those circuits.

1306  Consider Covered aerial medium-voltage (CAMV) systems. This hardware attaches to poles and 

1307 overhead wires to add strength and stability to the wires. The added stability makes the 

1308 distribution network more resilient to contact with trees and debris, and is especially useful in 

1309 narrow rights of way with large concentrations of trees.

1310  Other potential solutions include various pole line configurations that can help minimize 

1311 restoration efforts.
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1312  In fire prone areas, consider using concrete, heavy steel, or other non-flammable and warp 

1313 resistant structures to put conductors and equipment overhead. This makes the survival of the line 

1314 more likely. However, consider driver safety in this upgrade. Because these structures are 

1315 stronger, consider moving them further from the road rights-of-way so the likelihood of hitting a 

1316 pole is reduced if an automobile leaves the road. 

1317

1318 Non-Construction Strategies. As discussed in Section 7.2, the effects of a number of natural hazards can 

1319 be mitigated without hardening or other construction strategies of the infrastructure. Some possible non1320 construction strategies for improving the resilience of energy infrastructure include the following:

1321

1322  Trim trees and other potential obstructions as far as practical within the right of way.

1323  Use submersible equipment in underground substations, which can be accomplished in the case of 

1324 city-run electric utilities or city-owned substations. Submersible equipment stops almost any 

1325 water-based issue with substation operation, whether from weather events, water main breaks or 

1326 flooding from other sources. 

1327  Minimize the number of splices in conductors and in ducts that carry the splices. Where possible, 

1328 position splices in conductors and ducts as far away from water mains as possible and in easily1329 accessible locations. Note: in high volume rain areas, storm drains can be as large an issue as 

1330 water mains.

1331  Consider heavy wall insulation cables, type TC cables, and type MC cables. Heavy wall 

1332 insulation cables are more resistant to physical damage and moisture, providing better resilience 

1333 to severe weather conditions than thin wall insulation cables. Type TC cables are used in 

1334 industrial applications for power and control applications. TC cables have a moisture-resistant 

1335 jacket and are rated for use in wet conditions. Type MC cables are also moisture-resistant and 

1336 rated for use in wet conditions. In addition, MC cables are also crush-resistant.

1337 Electrical Infrastructure in Buildings. Specific to energy infrastructure in buildings, the National 

1338 Institute of Building Sciences recommends that ―during the facility design and/or re-build development 

1339 process, building projects have a comprehensive, integrated perspective that seeks to:

1340  Reduce Heating, Cooling, and Lighting Loads through Climate-Responsive Design and 

1341 Conservation Practices

1342  Use passive solar design; orient, size, and specify windows; and locate landscape elements 

1343 with solar geometry and building load requirements in mind. 

1344  Use high-performance building envelopes; select walls, roofs, and other assemblies based on 

1345 long-term insulation and durability requirements.

1346  Employ Renewable or High-Efficiency Energy Sources

1347  Renewable energy sources include solar water heating, photovoltaic (PV), wind, biomass, and 

1348 geothermal. 

1349  Evaluate the use of building scale to take advantage of on-site renewable energy technologies 

1350 such as day lighting, solar water heating, and geothermal heat pumps. 

1351  Consider the use of larger scale, on-site renewable energy technologies such as photovoltaics, 

1352 solar thermal, and wind turbines. 

1353  Evaluate purchasing electricity generated from renewable sources or low polluting sources 

1354 such as natural gas.

1355  Specify Efficient HVAC and Lighting Systems

1356  Use energy efficient HVAC equipment and systems that meet or exceed 10 CFR 434. 

1357  Use lighting systems that consume less than 1 watt/square foot for ambient lighting. 
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1358  Use Energy Star® approved and/or FEMP-designated energy efficient products or products 

1359 that meet or exceed Department of Energy standards. 

1360  Evaluate energy recovery systems that pre-heat or pre-cool incoming ventilation air in 

1361 commercial and institutional buildings. 

1362  Investigate the use of integrated generation and delivery systems, such as co-generation, fuel 

1363 cells, and off-peak thermal storage. 

1364  Optimize Building Performance and System Control Strategies

1365  Employ energy modeling programs early in the design process. 

1366  Use sensors to control loads based on occupancy, schedule and/or the availability of natural 

1367 resources such as daylight or natural ventilation. 

1368  Evaluate the use of modular components such as boilers or chillers to optimize part-load 

1369 efficiency and maintenance requirements. 

1370  Evaluate the use of Smart Controls that merge building automation systems with information 

1371 technology (IT) infrastructures. 

1372  Employ an interactive energy management tool that allows you to track and assess energy 

1373 and water consumption.‖ 5

1374 The CaLEAP organization has identified additional recommendations for building and retail owners, 

1375 including:

1376  Ensuring emergency, life safety, high priority, and general building circuits are well segregated in 

1377 building wiring design and breaker panel layouts.

1378  Ensuring building automation systems take advantage of segregated load grouping mentioned 

1379 above, are standards based (e.g. BACNet), and are capable of accepting utility load control 

1380 signals (e.g. OpenADR).

1381  Key community facilities necessary to ensure socio-economic continuity without internal backup 

1382 generation capability are configured to permit easy, safe connection to external mobile generation 

1383 (e.g. through standardized connectors at the outside service entrance)

1384 7.6.3. Strategies for Existing Construction

1385 The previous section on strategies for new construction discussed recommendations by the National 

1386 Institute of Building Sciences in detail. Most of the ideas expressed also apply to existing construction 

1387 strategies. However, in new construction, there is a larger set of opportunities for energy efficiency and 

1388 resiliency since nothing has been built yet.

1389 In general, when replacing equipment, and other components within the energy system, each component

1390 should be considered and, where more resilient, better reliability choices are available, communities

1391 should not replace with the same equipment when practical.

1392 Construction Strategies. Similarly to new/future infrastructure, construction strategies, including the 

1393 following, can be used to enhance the resilience of existing infrastructure:

1394  Strengthen and reinforce critical lines leading to population centers or other critical loads. For 

1395 instance, adding line reinforcements to lines that serve a hospital or fire station makes them more 

1396 resilient to wind, ice, and branch loads.

1397  When adding new equipment to poles, perform loading assessment to ensure that the pole is not 

1398 over-stressed.

1399  Consider Covered aerial medium-voltage (CAMV) systems.

1400  Consider replacing overhead lines with underground systems. As discussed previously, this 

1401 requires careful consideration and a cost/benefit analysis. However, in many cases, the ability of 

 

5

Source: National Institute of Building Sciences, http://www.wbdg.org/design/minimize_consumption.php
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1402 underground systems to provide uninterrupted service (or service with limited outages) during 

1403 severe weather events has societal and economic benefits that deserve consideration. Due to the 

1404 increased costs associated with undergrounding, some options include:

1405  Underground only the worst performing circuits, or section(s) of a circuit.

1406  Underground circuits based on the largest number of customers services.

1407  Underground circuits that are difficult to access (especially during weather-related hazard 

1408 events).

1409  Consider moving overhead equipment higher so the fire has to reach further to do significant 

1410 damage. 

1411  A second electrical system path to critical buildings is a resilient design. The alternative electrical 

1412 path can be from local generation or from an independent path into the area that can be traced 

1413 back to a power source without crossing the other path.

1414  Make sure the soil types and insulation properties of the soils are known when burying a line. If 

1415 the line is buried too shallow, the line will end up out of commission as often as an overhead 

1416 system and the resulting problems will take far longer to find and fix. Broken overhead 

1417 infrastructure is typically found by simple visual inspection, while failed underground 

1418 infrastructure requires investigation by digging or specialized equipment. In some instances, one 

1419 costly option is to abandon in place and replace the whole distance of the splice to restore the 

1420 system quickly. 

1421  Use modern flexible fuel lines for the run between the fuel tank and the shelter or skid upon 

1422 which the generator sit. This installation not only minimizes leaks from vibration, but keeps pipes 

1423 with lower thermal tolerance away from hot parts of the generator. A cracked or broken insulated 

1424 fuel line may take hours to detect in an emergency situation because of the chaos. Typically the 

1425 leak gets worse as the generator vibrates, and the loss of fuel can become significant. A visual 

1426 inspection of the fuel lines after an earthquake should be conducted as quickly as possible to 

1427 prevent a hazmat event, fire, or an early shutdown of a back-up generator.

1428 Non-Construction Strategies. In many cases, improving the resilience of existing infrastructure may be 

1429 more easily accomplished through non-construction strategies. Some possible non-construction strategies 

1430 for improving the resilience of existing energy infrastructure include the following: 

1431  Trim trees and other potential obstructions as far as practical within the right of way.

1432  Perform regular tree trimming and line inspections.

1433  Perform regular pole inspections. Look for excessive pole loading due to telephone, cable

1434 (television), and internet-related equipment. If the pole is wooden, check for decay. Check the 

1435 foundation of the poles to ensure they are properly embedded and stable. If there is erosion 

1436 around the footing or the pole is leaning, add guy wires or reset/replace the pole. Consider heavy 

1437 wall insulation cables, type TC cables, and type MC cables.

1438  Inspect underground splices and equipment on a scheduled basis to make sure seals are intact and 

1439 that nothing has destroyed the waterproof capability of the connections. 

1440  Using bulkheads that are strong enough to resist the water pressure on the other side in ducts can 

1441 help protect equipment and minimize damage as well as close off a path of least resistance that 

1442 will spread the damage from a break. If a duct runs down a 200 foot high hill and the main breaks 

1443 at the top, the bulkhead would have to resist approximately 400 psi of pressure in the duct. 

1444 Understanding this in inspection and design is useful. A strong bulkhead at the top of the hill can 

1445 provide a simple solution that ensures the duct never fills with water. 

1446  Have an adequate stock of spares (poles, transformers, line, etc.) on hand for fire prone areas, and 

1447 do not use them for routine work. If emergency spares are used in routine work, then it will take 

1448 even longer to do restoration.
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1449  Aggressive vegetation management is critical to the safety of both overhead and underground

infrastructure61450 . This includes removing trash that is illegally dumped on rights-of-way. Recently, 

1451 over 200 tires were removed from an illegal dumping pile on a right-of-way. These tires would 

1452 have burned hot enough to destroy the line if they had ignited.

1453  If possible, cutting off power before wildfire gets to the line allows equipment and lines time to 

1454 cool and may save the system from destruction. If people have been removed from an area, do not 

1455 hesitate to turn off power a couple of hours before the fire reaches the area, allowing equipment 

1456 maximum time to cool. This proactive action can also avoid having fires start as the result of a 

1457 power line going down or overheating equipment, thereby negating any perimeter that may have 

1458 been created.

1459  Controlled burns for vegetation management and invasive species reduction can impact 

1460 infrastructure if vegetation is close to rights of way. Ensure that precautions are taken prior to 

1461 controlled burns – about 20% of electrical outages from fires are from controlled burns.

1462  Proper grounding and inspections of grounding equipment greatly minimize the chance 

1463 transformer fire can occur from lightning. Standards exist both for how to ground and how to 

1464 inspect the grounding. Poles in areas that are susceptible to fire should be inspected more often 

1465 or, the use of non-flammable poles, like concrete, is an intelligent hardening mitigation effort.

1466 Installing and maintaining lightning arrestors and cut outs in the distribution grid can minimize the area 

1467 that a single lightning strike affects but, in the case of cut-outs, once it is triggered, manual fuse 

1468 replacement is required. Replacing cutouts with sectionalizers means that the equipment has a chance to 

1469 stop the lightning and automatically attempt a reset to restore power. On the customer side of the meter, 

1470 existing construction can be readily retrofit with external generation support connectors as previously 

1471 noted for new construction. If an existing facility is considering adding any form of self-generation 

1472 systems, consider upgrading building circuits at the same time to segregate load types. If a building 

1473 automation upgrade is being considered, ensure that it meets the suggestions previously noted for new 

1474 construction. As noted previously, consider using the USACE Emergency Power Facility Assessment 

1475 Tool (EPFAT), which allows public entities to input generator and bill of material requirements to 

1476 expedite temporary power installation support services. 

1477 7.7. References

1478 ALA 2005. Guidance for Assessing the Performance of Oil and Natural Gas Pipeline Systems in Natural 

1479 Hazard and Human Threat Events, American Lifelines Alliance draft report to the Federal Emergency 

1480 Management Agency and the National Institute of Building Sciences.

1481 ALA 2006. Power Systems, Water, Transportation and Communications Lifeline Interdependencies,

1482 American Lifelines Alliance draft report to the Federal Emergency Management Agency and the National 

1483 Institute of Building Sciences.

1484 ASCE 2013. "2013 Report Card for America's Infrastructure," American Society of Civil Engineers.

1485 Andrews, E., M.A. Lazurus, and J. Aliberti. 2013. ―Community Resilience: Reliable Back-up Power.‖

1486 Saint Louis University Center for Sustainability, 2013 SDRC. http://www.slu.edu/sustainability/ 

1487 events/events-archive/2013-sdrc/2013-sdrc-presentations

1488 Fuel Cell and Hydrogen Energy Association 2014. "Resiliency of Stationary Fuel Cells and the Natural 

1489 Gas Grid," National Institute of Building Sciences.

1490 Hampson, A., T. Bourgeois, G. Dillingham and I. Panzarella. 2013. Combined Heat and Power: Enabling 

1491 Resilient Energy Infrastructure for Critical Facilities, ONRL/TM-2013/100, Oak Ridge National 

1492 Laboratory.

 

6

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1493 IEEE 1995. Recommended Practice for Emergency and Standby Power Systems for Industrial and 

1494 Commercial Applications, IEEE Std. 446-1995.

1495 McDonough, P. W. 2013. "Post-Earthquake Checklist for Natural Gas Systems," American Society of 

1496 Civil Engineers.

1497 Nadeau, J. P. 2007. "Improving the Resiliency of the Natural Gas Supply and Distribution Network," 

1498 Naval Postgraduate School.

1499 NFPA 2005. NFPA 70: The National Electrical Code, National Fire Protection Association.

1500 NFPA 2013a. NFPA 110: Standard for Emergency and Standby Power Systems, National Fire Protection 

1501 Association. 

1502 NFPA 2013b. NFPA 111: Standard on Stored Electrical Energy Emergency and Standby Power Systems,

1503 National Fire Protection Association.

1504 NJOEM. 2014. Retail Fuel Station Energy Resiliency Program, New Jersey Office of Emergency 

1505 Management, http://www.ready.nj.gov/programs/retail-fuel-station.html

1506 Oregon Seismic Safety Policy Advisory Commission (OSSPAC). 2013. The Oregon Resilience Plan,

1507 Salem, Oregon.

1508 USEIA 2009. ―Residential Energy Consumption Survey: Space Heating by Type of Housing Unit 

1509 (HC6.1),‖ U.S. Energy Information Administration, http://www.eia.gov/consumption/residential/data/

1510 2009/index.cfm#undefined . 

1511 USEIA 2014a. ―High cost, oil-fired generation crates potential for shift in Hawaiian electric sources,‖ 

1512 U.S. Energy Information Administration, http://www.eia.gov/todayinenergy/detail.cfm?id=15091. 

1513 USEIA 2014b. ―U.S. Percent Utilization of Refinery Operable Capacity,‖ U.S. Energy Information 

1514 Administration, http://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=MOPUEUS2&f=A. 

1515 Clark, Tony, and Meidhof, Robin Z. 2013, ―Ensuring Reliability and a Fair Energy Marketplace: Energy 

1516 Innovation Series and Sixth Annual Schultz Lecture, University of Colorado, Boulder, Colorado (October 

1517 22, 2013

1518 Pentland, William, 2013, ―Rethinking Grid Resilience: Are we Golf Plating the Electric Grid?‖ October 

1519 11, 2013 (http:/lwww.forbes.com/sites/williampentland/2013/10/18/rethinking-grid-resilience-are-we1520 gold-plating-the-electric-gridl)

1521 NARUC 2013, Keogh, Miles and Cody, Christina. The National Association of Regulatory Utility 

1522 Commissioners, NARUC Grants & Research ―Resilience in Regulated Utilities‖ November 2013

1523 NIST Special Publication 1108R2: NIST Framework and Roadmap for Smart Grid Interoperability 

1524 Standards, Release 2.0, Office of the National Coordinator for Smart Grid Interoperability February 2012

1525 10-21-2014, National Institute of Building Sciences, 

1526 http://www.wbdg.org/design/minimize_consumption.php