What’s Happening with NERC Reliability Standards?

Currents Newsletter, Michigan Municipal Electric Association
Daniel E. Cooper, P.E.

Reliability has always been an issue for electric utilities. Municipal utilities, with their local connections and close relationships with their customers, have generally prided themselves on their reliable operations. So the new reliability standards shouldn’t be a big deal, right? Unfortunately, the answer is the standards are a big deal, even for utilities with strong reliability records.

Reliability standards have been around for a while. The North American Electric Reliability Corporation, or “NERC”, was started in 1968 in response to a major blackout. There was a recognition that the increasing level of transmission interconnections created a very real possibility an outage on one utility’s system could “cascade”, pulling other utility systems down. NERC was created as a voluntary organization that helped utilities (mainly the larger investor owned ones) create voluntary standards to increase reliability of the interconnected Bulk Electric System (the “BES”). NERC operated on this voluntary basis for a number of years.

However, the evolution of the electric industry changed things. The increase in transmission interconnections, power being shipped from one area to another, and the appearance of independent power producers caused an increased risk of cascading outages affecting large areas. The risk was greatly enhanced by the paradigm shift that occurred in the industry. Instead of (mainly) large utilities with discrete control areas and an “obligation to serve”, the electric industry began to transition to NERC’s Functional Model that broke the electric utility industry down into an alphabet soup of theoretically independent functional entities. The functional entities, ranging from Distribution Providers to the Electric Reliability Organization, created a potential vacuum concerning who was responsible for maintaining system stability to “keep the lights on”. NERC’s response to the potential responsibility vacuum was to make everyone responsible through an expanded and reworked set of reliability standards.

The question of the effectiveness of reliability standards came to a head following the August 2003 blackout of a sizable portion of the central and eastern United States and Canada. NERC was reformulated from what was effectively a voluntary trade group to a self-funding quasi-governmental organization operating under delegated authority from the Federal Energy Regulatory Commission (“FERC”). The most significant change resulting from the re-invention of NERC was that the reliability standards to protect the BES changed from being voluntary to being mandatory and enforceable. NERC’s new ability to enforce the standards included the ability to levy serious financial penalties of up to $1,000,000 per occurrence per day.

In practice, the mandatory reliability standards have a significant impact on many utilities, including municipal utilities. Compliance activities can require new procedures, increased documentation, and possibly changes in labor agreements. Utilities are also subject to periodic audits of their compliance. The audit is a formal process that contains a combination data requests, interviews, spot checks and detailed reviews of utility procedures and documentation. The actual audit is performed by teams of knowledgeable utility and regional reliability organization employees that are convened by a Regional Reliability Entity (“RE”), such as ReliabilityFirst, to visit and review the utility being audited. The different functional areas are audited on different schedules. For example, utilities that are registered as Generation Owners or Generation Operators are audited more frequently than utilities that are registered as Distribution Providers or Load Serving Entities. NERC’s mandatory standards have been in place long enough that even the functions with the longest time between audits – Distribution Providers and Load Serving Entities – are now coming up for audits.

Audits can and have resulted in identification of potential reliability standards violations. The potential alleged violations can lead to a requirement for a mitigation plan and possibly a monetary penalty. In some cases, the audit team has also recommended the utility being audited should be registered under additional reliability functions. The results of the individual audits vary. There have been some common themes, though. A lack of documentation adequate to prove compliance has been a frequent problem for initial audits for all reliability functions. Inadequate or insufficiently documented Vegetation Management Plans have been an issue for Transmission Owners. A failure to document or follow a time-specific testing plan for protective devices has been a problem for many Generation Owners and Transmission Owners. Cyber-security concerns have expanded as more attention is focused on the area. Notably, an asymmetry in the viewpoint of the audit participants also affects audit outcomes. The auditors, NERC and the RE’s have a huge exposure if there are significant blackouts, but don’t bear the cost of compliance. Utilities support reliability, but are sensitive to the cost/benefit tradeoff of compliance activities. Such differences in viewpoints can and do lead to differences in interpretation.

So what can a prudent utility manager do in regards to reliability compliance? Joint Registration Organizations, such as Michigan Public Power Agency operates, can reduce burdens and concerns for smaller utilities with little or no generation. Utilities with generators that are 20 MVA or larger or plants that are 75 MVA or larger, as well as utilities that own transmission that operates at 100 kV or higher may want to staff in-house expertise, make use of consultants, or both.

Any utility that is individually registered for reliability functions should document its processes and procedures for reliability compliance in its registered area. The utility should follow the documented procedures. However, documented procedures shouldn’t be defined too tightly. It is much better to have a testing procedure that says you test relays every five years with the testing being performed in a 60 day window around the anniversary date than to say you will test the relay every 1,826 days.

Finally, if you find your utility has violated a standard, react promptly. Consider outside counsel. Recognize you will almost certainly be better off to self-report the violation than to wait until it comes out in an audit. Then undertake corrective action, including negotiation of a mitigation plan with the RE if necessary.

And remember – we are all just trying to keep the lights on.

Dan Cooper is a Consulting Engineer with the law firm of Jennings, Strouss & Salmon.

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