My most recent post on substations has drawn a lot of interest. It points to a couple problems in the CIP-002-5.1 Attachment 1 criteria for which there aren’t clear answers. I invited people to send me other examples of problems with the criteria, and Stacy Bresler of EnergySec immediately brought one up.
His is quite simple: The words “Transmission Facilities” (both capitalized) are used several times in the criteria. Since they are capitalized, this means these are defined terms – either together or separately. There is no NERC definition for “Transmission Facility”, but there are definitions for both “Transmission” and “Facility”. However, Stacy points out that combining the two definitions really doesn’t produce much enlightenment about what really is a transmission facility.
I think the problem is mainly with the “Transmission” definition:
An interconnected group of lines and associated equipment for the movement or transfer of electric energy between points of supply and points at which it is transformed for delivery to customers or is delivered to other electric systems.
I believe Stacy’s concern is that many substations combine elements that would normally be called “transmission” and “distribution”. Where exactly do you draw the line between them? This is no idle concern, since an entity that doesn’t properly draw that line will end up either spending much more money and time than they need to protecting systems associated with purely distribution elements (lines, transformers, breakers, etc), or else they’ll end up not properly protecting their transmission elements – which can result in big fines.
Stacy does point out there is a workable definition of “Transmission Facility” that does provide the specificity that’s required. That’s the good news. The bad news is that this definition only applies to entities in the province of Alberta, since it is found in the glossary of the Alberta Electric System Operator (AESO) – which can be thought of as a combination of NERC and PJM for that province.
Stacy provided a link to the glossary, but here is the definition, in all its glorious specificity:
an arrangement of conductors and transformation equipment that transmits electricity from the high voltage terminal of the generation transformer to the low voltage terminal of the step down transformer operating phase to phase at a nominal high voltage level of more than 25 000 volts to a nominal low voltage level of 25000 volts or less, and includes
(i) transmission lines energized in excess of 25000 volts,
(ii) insulating and supporting structures,
(iii) substations, transformers and switchgear,
(iv) operational, telecommunication and control devices,
(v) all property of any kind used for the purpose of, or in connection with, the
operation of the transmission facility, including all equipment in a substation
used to transmit electric energy from (A) the low voltage terminal, to (B) electric distribution system lines that exit the substation and are energized at 25 000 volts or less, and
(vi) connections with electric systems in jurisdictions bordering Alberta, but does not include a generating unit or an electric distribution system.
My guess is this definition will get entities a lot closer to what they need than the anemic NERC definition of Transmission does.[i] Does that mean everybody should start using Alberta’s definition in order to “slice and dice” the elements in their substations between Transmission and Distribution? Well, I think this at least gives you a template for working out your own definition (or maybe NATF or some other organization can write one).
As one of my next posts will discuss, when NERC doesn’t define a term or only vaguely defines it (and when no guidance is put out to remedy this problem, which of course is the rule with CIP v5, not the exception), I think the door is open for the entity to find something that works and use that to guide their efforts. Just be sure to document it, and inform your Regional Entity you’re doing this…unless they have some better definition for you to use.
Of course, the best solution to this problem is for NERC to provide guidance on this question, as well as many others. My next post will discuss a new initiative NERC is undertaking to try to provide some guidance, and the challenges involved with that effort. But don’t start thinking miracles are on the way.
The views and opinions expressed here are my own and don’t necessarily represent the views or opinions of Honeywell.
[i] In the Guidance and Technical Basis section of CIP-002-5.1 (page 23), the SDT did mention that entities should separate Transmission (called “BES Operations”) from Distribution Facilities in a substation:
However, in a substation that includes equipment that supports BES operations along with equipment that only supports Distribution operations, the Responsible Entity may be better served to consider only the group of Facilities that supports BES operation.
This statement seems to assume one of two things:
1. The NERC definition of Transmission is sufficiently clear that everyone will be able to distinguish these Facilities with no problem; or
2. There isn’t any clear line between Transmission and Distribution Facilities, meaning that whatever the entity thinks is appropriate will be fine with the auditors. This is implied in the sentence that begins the paragraph from which the above sentence is taken: “When the drafting team uses the term ‘Facilities’, there is some latitude to Responsible Entities to determine included Facilities.” Of course, just because the SDT said there is “some latitude” doesn’t mean you’ll be given any latitude at all when audit time comes.
This is simply another example of the bright-line criteria requiring a lot of interpretation. And I don’t see anybody – other than the regions on an individual basis, and even then it’s quite spotty – to do this.