The Power of Physical Security
Print Issue: May 2015
Any utilities security expert can effortlessly recite the details. In April 2013, someone snuck into an underground vault near a freeway in San Jose, California, and cut several telephone cables. Then, 30 minutes later, snipers shot at an electrical substation in Metcalf, California, for almost 20 minutes, knocking out 17 transformers that funnel power to Silicon Valley, before fleeing the scene and evading capture.
A major blackout was prevented by rerouting power around the downed station, but the attack caused more than $15 million in damage and brought physical threats to the electric grid to the forefront of discussions about the security of the United States’ critical infrastructure. It quickly became clear that cyberattacks were not the only threat to the U.S. power supply.
Two years have passed since the incident, and, while the snipers remain at large, the utility industry is taking steps to deter any future attacks.
“Because the grid is so critical to all aspects of our society and economy, protecting its reliability and resilience is a core responsibility of everyone who works in the electric industry,” said acting Federal Energy Regulatory Commission (FERC) chairman Cheryl LaFleur in a statement in March 2014. (LaFleur was named permanent chairman in July 2014.) Following LaFleur’s statement, FERC directed the North American Electric Reliability Corporation (NERC) to develop new standards requiring owners and operators of the bulk-power system to address risks due to physical security threats and vulnerabilities.
The FERC order asked NERC to create a standard to identify and protect transmission stations, substations, and associated primary control centers that could cause widespread outages if compromised.
From those instructions, a 10-person drafting committee created the CIP-014 standard that focuses on transmission assessments and physical security. The standard requires transmission station and substation owners to perform a risk assessment of their systems to identify facilities that could have a critical impact on the power grid.
The order also requires owners and operators to develop and implement a security plan to address potential threats and vulnerabilities.
The electric system is made up of three components: generators—coal fired, biomass, solar, and wind—that produce electricity; transmission—taking the electricity from the power source and moving it somewhere, such as a substation; and distribution—power moving from a facility to the meter in a home, business, or other building.
When electricity moves from a generation station, such as a wind farm, it goes to a substation that normally has transformers that decrease the voltage, often from 500 to 230 kilovolts (kV). From there, the substation transmits the power to another substation, which usually lowers the voltage even further to 115 kV so it can be used in residential and commercial facilities.
CIP-014 applies to transmission substations in the electric system, not the generators or the distribution stations. However, it doesn’t apply to all 55,000 transmission substations in the country, explains Allan Wick, CPP, PCI, PSP, a member of the standard drafting committee.
Instead, the standard relies on categories that determine which facilities must comply with the standard. The standard takes effect if a system that is “rendered inoperable or damaged as a result of a physical attack could result in instability, uncontrolled separation, or cascading with an interconnection,” Wick explains.
Because of these criteria, CIP-014 applies to transmission facilities that operate at 500 kV or higher, or single facilities that operate between 200 kV and 499 kV where the substation is connected at 200 kV or higher voltage to three or more other transmission stations that have an “aggregate weighted value” higher than 3,000 kV.
This means that few transmission substations will have to comply with standards. “By the time you use those criteria against what’s in the standard, [CIP-014] will only apply to 200 or fewer substations in the United States,” Wick says. The standard also applies to the control centers that operate those 200 substations—which are owned by roughly 30 different companies.
FERC approved CIP-014 in November 2014, officially kickstarting the compliance process that owners need to complete by the first implementation date in October 2015. Their first responsibility is to perform an initial risk assessment (Requirement 1) to identify the transmission stations and substations the standard may apply to. Owners then have to identify the primary control centers that operationally control each transmission station or substation identified in the risk assessment.
Once these steps have been completed, owners will have 90 days to have an unaffiliated third party verify their assessments (R2). This third party can be a registered planning coordinator, transmission planner, reliability coordinator, or an entity that has transmission planning or analysis experience.
If the third party adds or removes a transmission station or substation from the original assessment, owners then have an additional 60 days to modify their risk assessments or document the basis for not making the appropriate changes.
Additionally, if the primary control centers identified are owned by a company other than the transmission station, that owner needs to be notified (R3) within seven days following the third-party verification that it has operational control of the primary control center.
After the initial risk assessment has been completed, transmission owners that are covered by the standard will perform subsequent assessments at least once every 30 months. Transmission owners that are not covered by the standard are also required by law to perform assessments, but only once every 60 months.
Once the transmission analysis and identification have been completed, owners are required to conduct evaluations of the potential threats and vulnerabilities of a physical attack (R4) to each of their respective transmission stations, substations, and primary control centers.
These evaluations should include unique characteristics of the identified and verified transmission stations, substations, and control centers. For example, characteristics could include whether the substation is rural or urban, if it’s near a major highway, or if it’s in a valley.
For instance, the substation could be “set down in a small valley, so there are areas around it [from which] a shooter could either shoot the transformers or even use a rocket-propelled grenade to shoot something into it,” Wick explains.
Owners also need to detail any history of attacks on similar facilities, taking into account the “frequency, geographic proximity, and severity of past physical security related events,” according to the standard. CIP-014 asks owners to include intelligence or threat warnings they’ve received from law enforcement, the Electric Reliability Organization, the Electricity Sector Information Sharing and Analysis Center, and government agencies from either the United States or Canada.
Once these evaluations have been completed, and no more than 120 days after R2 is completed, owners are required to develop and implement a documented security plan and timeline that covers their respective transmission stations, substations, and primary control centers (R5).
Within the security plan, owners should include law enforcement contact and coordination information, provisions to evaluate evolving physical threats and their corresponding security measures, and resiliency or security measures designed “collectively to deter, detect, delay, assess, communicate, and respond to potential physical threats and vulnerabilities identified” during R4.
The drafting committee chose this language specifically, Wick says, because “you can’t just do one of those—you need to put them together as a group to ‘deter, detect, delay,’ because those are the primary components…in a layered security program.”
The committee was also purposely less prescriptive about methods owners can use as part of their security measures. “We tried to build in maximum flexibility to arrive at the same end state for everybody,” Wick says. For instance, to delay someone “you can do that several different ways. You could have a 20-foot -high wall with razor tape, or you could do it with a chain link fence; there are so many options that you could use to mitigate the threats and vulnerabilities that are identified in R4.”
This nonprescriptive method has faced some criticism, but many others think it’s beneficial. The regulators “are not really telling you to go out and spend all sorts of money on increased cameras, spending a lot of money on fences,” says Rich Hyatt, PCI, manager of security services for Tucson Electric Power. “They’re kind of promoting that you should harden up your site, like vegetation removal, signage…it’s not like the government’s coming in and telling you to spend $5 million per substation.”
The committee is also allowing owners to take a twofold approach by giving them the opportunity to build in resiliency on the operational side and protect their assets with security measures.
For example, Tucson Electric Power is increasing its resiliency by hardening its substations, says Hyatt, who’s also a member of the ASIS International Utilities Council. This is important because sometimes transformers malfunction. “There’s always the likelihood of sabotage, but we also have a threat of malfunction or weather-related issues, or manmade stuff that could go into a transformer being taken out,” he explains.
Hyatt is also working with substation employees to improve emergency communication, another issue addressed in the standard. “We’re also engaging our…substation folks to beef up their emergency response and have additional spare parts in their inventory so they can respond if a transformer got shot out—we could get it back online quicker,” he explains.
However, Jake Parker—director of government relations for the Security Industry Association (SIA)—says physically protecting assets is the better way to go for utilities security. “We think that physical security measures are much more cost effective because the cost of hardening the structure can also be extremely steep,” he explains.
Once owners have drafted and implemented their physical security plans, they then need to be verified again by a third party reviewer (R6) within 90 days. This reviewer can be an entity or organization with physical security experience in the electric industry and whose review staff: has at least one member who holds either a Certified Protection Professional (CPP) or Physical Security Professional (PSP) certification; is approved by the Electric Reliability Organization (ERO); is a government agency with physical security expertise; or is an entity or organization with law enforcement, government, or military physical security expertise.
The ASIS certifications requirement was included after a review of existing applicable certifications. “By holding one of those two certifications, it shows that you know what you’re talking about on physical security,” Wick explains. “We did reviews of any certification that had physical security requirements, and these were the only two that were suitable.”
If the reviewer recommends changes to the R4 evaluation or the security plan, owners then have 60 days to comply with those recommendations or document why they are not modifying their plans.
CIP-014 has an aggressive implementation timetable; Parker says he expects most utilities to have their physical security plans in place by spring 2016. There are no penalties for owners who do not comply with the new standard, although owners who do comply are required to keep documentation as evidence to show compliance for three years. NERC is responsible for enforcement.
Despite the lack of penalties and the limited number of transmission stations and substations covered by the standard, many companies say the standard has inspired them. CIP-014 has given companies guidance on increasing their physical security, according to Parker.
“We’re seeing, given the current environment and response to what happened at Metcalf…that utilities are finding it easier to justify security improvements across the board via rate increases,” he explains.
The rate increases are the funding mechanism utilities can use to pay for physical security improvements. They can do this by bringing proposals to their boards and justifying small rate increases “to cover the cost of the security upgrades because of the standard, but also because of the need to improve physical security of the electric grid overall,” Parker adds.
Hyatt agrees, saying that the industry is doing a “really good job” on being proactive in “policing up” and increasing the use of best security practices. The incident at Metcalf, he adds, has “actually increased security’s perception among executives where we work that physical security is just as important as cybersecurity.”