After pleading with Congress for so many years, and then at last winning the requisite legislative authority to impose mandatory and enforceable standards for electric reliability, to replace its legacy system of voluntary compliance, the North American Electric Reliability Council (NERC) finds itself at a curious juncture.
It wants to slow the transition.
Of course, NERC still urges federal regulators to stay on track as expected to approve a new set of electric reliability standards by June 1—in time to go live for this year’s summer peaking season. However, when it comes to assessing fines and penalties on those violating the new rules, NERC wants to put on the brakes. It wants the Federal Energy Regulatory Commission (FERC) to agree to a grace period of at least six months without general enforcement of monetary penalties—what some have called a “shakedown cruise.” That would allow the industry to gain familiarity with the thousand and more requirements contained in the 100-plus standards that NERC proposed last April. During the transition, extending to Jan. 1, 2008, NERC would evaluate reliability performance and calculate any penalties otherwise owed, which could run to a million dollars a day, per violation. But NERC would not collect any fines, except for violations seen as especially egregious.
Moreover, as was pointed out by the Edison Electric Institute, NERC did not even file its proposed “compliance monitoring and enforcement program” until Nov. 29. Thus, CMEP approval likely would occur very near the projected June 1 startup for compliance, leaving little time for regional reliability entities to tailor their enforcement plans to the CMEP template.
Thus, a delay in enforcement could help NERC put its house in order, but could expose FERC to embarrassment.
Consider, for example, a conversation that transpired at a technical conference held in Washington, D.C., to explore options for reviewing and approving reliability standards not yet flushed out. On that occasion, FERC heard testimony from Kellan Fluckiger, executive director of the electricity division of the Alberta Department of Energy, as he recounted how the Western Interconnection had dealt with unfinished standards in adopting its contractually binding Reliability Management System (RMS):
“One of the things we did in the West with some standards,” he noted, was “to shadow enforce them, meaning violations were noted and publicized, but there was no monetary penalty … for some period of time—six months, a year, or some time to allow the further development of the precise enforcement mechanism.”
Echoing that idea was Charles Yeung, executive director for interregional affairs at the Southwest Power Pool, who testified on behalf of the ISO/RTO Council. He suggested a sort of triage, with regulators moving quickly to fix and approve the high-risk standards that “fall into a financial sanctions category,” but leaving others for voluntary compliance, as per the old regime.
“You’re not really taking anything away from the reliability,” he ventured, “by continuing to enforce them through that method.”
Yet his words seemed naïve to the then-sitting FERC Commissioner Nora Mead Brownell, who doubted if Congress would have patience, especially after giving NERC everything it had asked for in the 2005 Energy Policy Act (EPACT), which empowered NERC to issue mandatory rules:
“I’m thinking perhaps I don’t agree with your sense of urgency,” said Brownell.
“I would not [like] to be sitting in front of a congressional oversight hearing saying, yes, … you gave use this responsibility, but we kind of decided to take part of the old regime and let that continue.
“I don’t see that reflected in EPACT. … I certainly don’t want to be sitting in those chairs.”
FERC Chairman Joseph T. Kelliher agreed with Brownell, as NERC already had been reporting violations for two years on an informal basis:
“They’ve just had two years of field testing in 2004 and 2005. To me, I’m focused on the summer of ’07. I think our job is to get as many standards that meet the statutory test enforceable before the summer of 2007.”
Thus, in its notice of proposed rulemaking issue last fall, in which it reviewed some 107 new and revised standards proposed by NERC, FERC declined to grant any blanket waiver of financial penalties for reliability violations. It explained that the industry already had had time to familiarize itself with the new regime. Instead, FERC said it would call for discretion in enforcement of penalties only for violations involving those industry entities having to comply with reliability standards for the first time. (See, Mandatory Reliability Standards for the Bulk Power System [NOPR], Docket No. RM06-16, issued Oct. 20, 2006, 117 FERC ¶61,084.)
With its refusal to OK a trial period, FERC has disappointed virtually the en-tire power industry, judging from the scores of comments filed in early January by utilities (public and private), regulators, trade associations, and regional reliability organizations (RROs). Yet other findings also provided cause for complaint.
Thus, the industry overall offered a scathing critique of many of FERC’s NOPR recommendations. Public power complained of high compliance costs for small municipal systems and questioned whether FERC had given full faith to the Regulatory Flexibility Act (5 U.S.Code secs. 601-612), which otherwise protects small business from onerous regulations. Cogenerators worried about protecting behind- the-meter generation from unwarranted interference, and that standards would not remain fuel- and resource-neutral, making it difficult to promote demand-response resources for ancillary services, such as contingency reserves or even AGC—automatic generation control.
Overall, the industry appeared nearly unanimous in faulting FERC’s interpretation and handling of several key ideas. Those concepts included (1) the “NERC Functional Model,” (2) NERC’s “Statement of Compliance Registry Criteria,” and (3) the basic definitions of the terms “bulk power system,” and “bulk electric system.”
No one faults the commission much for its sense of urgency to get enforceable standards in place by June 1. Rather, the comments suggest that FERC has overshot its authority, both in telling NERC how to refine the standards now awaiting approval, and in defining the sectors and players within the electric utility industry that will owe compliance to the new regime.
The NOPR has proven particularly awkward for FERC since in many ways the commission remains a bystander to the process: powerless to make things happen, yet still liable for failure, especially in the eyes of Congress.
EPACT sec. 1211 (Federal Power Act sec. 215) instructs FERC in approving reliability to standards to give “due weight” to NERC’s “technical expertise” as the nation’s one and only federally certified Electric Reliability Organization, or ERO. The law gives primacy to the commission to judge whether a particular standard will interfere with electric competition, but otherwise, it envisions that standards will be developed, drafted, and vetted exclusively through NERC’s proprietary stakeholder process. Thus, FERC’s job lies only in deciding whether a particular standard is just and reasonable. That evaluation is governed in turn by FERC Order 672, which sets out a list of general factors that the commission may consider. A standard need not be optimal or represent the “best practice,” as long as it achieves its reliability goal effectively and efficiently. (See, Order 672, ¶¶323-331, Docket RM05-30, Feb. 3, 2006, 114 FERC ¶61,104.)
That means that if FERC finds shortcomings in a standard proposed by NERC, or wants to see it improved, it cannot just fashion a fix, or tell NERC what language to insert to correct the problem. Rather, as NERC itself has explained, the commission must state its directive “in the form of an objective to be achieved,” or as a “concern or deficiency to be resolved.” As NERC adds, the commission must “not prescribe a particular requirement, metric or specific language.”
For the commission to do so, NERC adds, “would, in effect, constitute setting the standard and would countermand the open standards process that the commission has approved and that is required by law.” (See, Comments of NERC, Docket No. RM06-16, p. 24, filed Jan. 3, 2007.)
To add insult to injury, NERC has sought to assist FERC by first identifying various commission directives in the NOPR that violate these guidelines, and then offering alternative preferred language .
Thus, where FERC instructs NERC to improve Requirement 3.1 in its disturbance control performance standard (BAL-002-0) so as to “include enough contingency reserve to cover any single event or single contingency, including a transmission outage,” NERC sees an improper instruction, and reprimands the commission, as follows:
“An improved directive would be: The commission directs NERC to resolve the ambiguity noted by the Staff Assessment [May 11, 2006] that Requirement 3.1 could be subject to multiple interpretations, one limited to only the loss of generation, whereas another interpretation would also consider … [etc.].”
And again, from the NOPR: “The commission proposes to direct NERC to modify BAL-002-0 to include a requirement that explicitly allows demand-side management as a resource for contingency reserves.”
Whereas NERC offers the following “improved” directive:
“To allow DSM or DCLM to be a resource for contingency reserves on a comparable basis as conventional generation or any other technology.”
Consider also that many proposed NERC standards contain ambiguous terms (“where practical,” “as soon as possible,” “where technically feasible,” etc.), and require a fair bit of housekeeping. Others still lack required elements to guide enforcement and assessment of penalties (NERC now refers to the required “levels of non-compliance” as “violation severity levels”). That can leave them unworthy of approval without further improvements, with the commission unable to dictate what those improvements might be.
It’s a no-win game for FERC.
The most peculiar aspect of NERC’s proposed standards and FERC’s responsive NOPR is this: There is no single list, guideline, or definition that can tell you exactly who must comply with the standards, and who is excused.
The only real touchstone is contained in EPACT, where Congress says that reliability standards will apply to “users, owners, and operators” of the “bulk power system” (BPS), which it then defines only as facilities and control systems necessary for running the interconnected transmission network (including generation), but excluding local distribution.
NERC’s proposals employ a comparable term, “bulk electric system” (BES), with an expanded definition that would apply largely (but not always) to facilities operated at voltages of 100 kV. Each RE (the regional reliability entity, by delegation agreement) will further define the scope of compliance. The REs would accomplish that in part by relying on NERC’s so-called “functional model” (a listing of 15 hypothetical industry entities, each assigned a unique task). REs would also refer to a document called the “Statement of Compliance Registry Criteria,” which would offer guidance on which industry players exert a “material impact” on the BES.
FERC by contrast, says it would follow NERC’s definition during an initial transition period. But thereafter, FERC writes in the NOPR that it likely would re-interpret the statute to cover what it sees as possible “gaps” in reliability. In short, FERC would up the ante and greatly expand the universe of entities subject to compliance. This prospect has raised howls of protest from public power interests on the difficulties faced by small systems, both to verify compliance requirements and then to carry them out to the letter (with all the associated software installations and record-keeping). FERC would mandate compliance with standards on a case-by-case, standard-by-standard basis. Utilities and others would need to study literally thousands of standards, requirements, measures, and metrics, simply to confirm the required scope of compliance.
To be precise, FERC would “interpret” EPACT’s BPS term more broadly and thus mandate compliance for all facilities 100 kV or larger, plus smaller facilities that could limit or supplement operations of the larger network, or serve “significant” load centers or local distribution networks. Compare that with EPACT, and with NERC’s BES definition. What do these differences imply, exactly, apart from a strict law-school-style analysis of the legislative history, and all other parallel interpretations of all the statutory terms?
According to NERC, reliability standards have targeted the problem of cascading or uncontrolled failures that spread through system equipment across regions, or even whole continents. Thus, NERC says it has narrowed it BES definition, the better to focus on the identified target.
By contrast, NERC suggests that FERC’s expanded definition focuses more on smaller entities and thus sets its sights on a somewhat different target—that being the problem of significant losses of retail load at the customer level. Thus, as NERC explains, FERC is confusing system reliability with supply adequacy—a requirement more commonly thought of as falling under state PUC purview.
And with lack of supply come the losses of load and service that bring disruptions to local economic activities, plus notorious coverage in the popular press, and tend to draw more attention from Congress, as compared with problems associated with the actual grid system, as a functioning machine.
The American Public Power Association echoes NERC’s thinking. It wonders whether FERC’s vision of reliability is tied more to law, or instead to how “newsworthy” the blackout might be. Consider the following quote, taken from pp. 37-38 of APPA’s NOPR comments, filed on Jan. 3:
“APPA notes in particular note 53 of the NOPR. The commission there observes that New York City’s 138-kV system is not included in the [Northeast] definition of the bulk electric system, and that certain 230-kV and 69-kV transmission facilities serving Washington, D.C., are not included in the [Mid-Atlantic] definition. …
“The commission nowhere explains why it thinks it needs to superimpose its own reliability jurisdiction of such facilities, which serve discrete (albeit newsworthy) load centers already subject to state reliability jurisdiction.”
Perhaps what we have here is a new regulatory paradigm, driven not by the terms of the Federal Power Act, but by FERC’s fear of being called on the carpet on Capitol Hill.