What Happened to the "Independent Study" of the Effects of Electric Industry Restructuring on Reliability?

Blackout Task Force Recommends an Independent Study
The Joint U.S. Canada Task Force Final Report on the widespread Northeast blackout of August 14, 2003 issued a number of recommendations. Number 12 was to "Commission an independent study of the relationships among restructuring, competition, and reliability." The blackout occurred mainly in states that had "restructured" their electricity industries. Sixteen states, mostly in the Northeast and Mid Atlantic area, have restructured, while the majority of states have not, and none have restructured since the California crisis of 2000 - 2001 and the demise of restructuring's major proponent, Enron in 2001.

The report indicated at page 94 that in New York, some of the power plants sold off to new owners during the "restructuring" orchestrated by the New York Public Service Commission had tripped at low disturbance levels, exacerbating the cascading outage:

In particular, it appears that some generators tripped to protect the units from conditions that did not justify their protection, and many others were set to trip in ways that were not coordinated with the region’s under-frequency load-shedding, rendering that UFLS scheme less effective. Both factors compromised successful islanding and precipitated the blackouts in Ontario and New York.

The Task Force Report at page 96 noted its frustration with information provided by the competitive generators:

Unfortunately, 40% of the generators that went off-line during or after the cascade did not provide useful information on the cause of tripping in their response to the NERC investigation data request. While the responses available offer significant and valid information, the investigation team will never be able to fully analyze and explain why so many generators tripped off-line so early in the cascade, contributing to the speed and extent of the blackout.

The Final Blackout report beginning at page 17 cites numerous violations of existing reliability requirements established by NERC, and at page 147 states:

The Task Force believes that the Interim Report accurately identified the primary causes of the blackout. It also believes that had existing reliability requirements been followed, either the disturbance in northern Ohio that evolved on August 14 into a blackout would not have occurred, or it would have been contained within the [First Energy Ohio] control area.

The Task Force did not really inquire as to why so many existing reliability requirements had not been followed by the utilities, but did say that concerns had been raised about a connection between restructuring and reliability that should be investigated:

[I]t is worthwhile for DOE and Natural Resources Canada (in consultation with FERC and the Canadian Council of Energy Ministers) to commission an independent expert study to provide advice on how to achieve and sustain an appropriate balance in this important area. Among other things, this study should take into account factors such as:

• historical and projected load growth
• location of new generation in relation to ogeneration and loads
• Zoning and NIMBY constraints on siting of generation and transmission
• Lack of new transmission investment and its causes
• Regional comparisons of impact of wholesale electric competition on reliability performance and on investments in reliability and transmission
• The financial community’s preferences and their effects on capital investment patterns
  
• Federal vs. state jurisdictional concerns
  
• Impacts of state caps on retail electric rates
  
• Impacts of limited transmission infrastructure on energy costs, transmission congestion, and reliability
  

Was New York Reliability Compromised by Restructuring?
At page 10 of its Final Report on the Blackout of August 2003, the Joint Task Force discussed the importance of coordinated "black start" capability to restore service after a major bulk power system outage:

To deal with a system emergency that results in a blackout, such as the one that occurred on August 14, 2003, there must be procedures and capabilities to use “black start” generators (capable of restarting with no external power source) and to coordinate operations in order to restore the system as quickly as possible to a normal and reliable condition.

Subsequent documents suggest that New York regulators allowed restructuring and the sale of power plants to occur without assuring solid "black start" capability. A NY PSC Staff Report issued in 2005 states:

Prior to the divestiture of its generating units, Con Edison's restoration plans designated certain Con Edison generating units for black start duty. When the generating units were divested, however, the contracts for the sale of the generating assets that had previously provided black start capability did not include terms providing for continuation of this service. Although the NYISO, Con Edison, and the generation owners were working to develop such agreements during the period between divestiture and the blackout in 2003, there were no formal agreements for New York City black start services, or rapid restoration services, or for payments to the new owners of the former Con Edison generators for such services. Consequently, the units had not been tested, and the lack of testing of the units appears to have directly contributed to the poor performance of most of the New York City black start generators* * * * Recent attempts to test the designated black start units in New York City, however, have shown that some major generators designated in the black start plan are still not yet available to operate should another blackout occur."

If this report is correct, more than two years after the August 2003 blackout, "black start" responsibilities and capability in New York's restructured electric industry still had not been fully resolved. Also, papers submitted by Orange & Rockland Utilities indicate that the new owners of a generating plant that O&R divested in the course of New York's restructuring failed to provide "black start" power when it was requested during the August 2003 blackout:

Furthermore, although Mirant’s units were included in O&R’s local restoration plan through September 26, 2005, when O&R called on Mirant to supply Black Start services during the blackout of August 2003, Mirant failed to provide such services, in effect, failing a live test of its Black Start capability.

Thus, it seems that restructuring did affect black start capability in New York.

In addition, questions have been raised whether the advent of restructuring and market structures for compensating transmission owners have altered incentives to repair major transmission line outages promptly. For example, the NYISO investigated whether Con Edison had financial incentives to slow repairs and keep a line out of service, and found no wrongdoing in 2002. The same line, from Westchester to Queens, was out of service in the summer of 2006, causing the NYISO and FERC to express concerns to Congress that New York was in danger of blackouts and load shedding in the event of extreme weather or additional outages. The congressional testimony indicated that Con Edison had projected repair of the outages in August. The lines were restored to service in July.

DOE Holds Conferences
The U.S. Department of Energy (DOE) and Natural Resources Canada responded to the Task Force Recommendation, but not by commissioning experts such as the National Academy of Sciences, or a university, or other consultants to conduct an independent research study.

Rather, two conferences were held for the purpose of hearing speaker panel presentations on volunteered white papers, which had widely differing conclusions. PULP has excerpted the papers, some of which identify links between electric industry restructuring and reduced reliability, such as this comment submitted by engineers experienced in prior blackout investigations:

Deregulation and the concomitant restructuring of the electric power industry in the U.S. have had a devastating effect on the reliability of North American power systems, and constitute the ultimate root cause of the August 14, 2003 blackout.

Their comments on the flawed investigation of the root causes of the blackout seem appropriate:

The government’s blackout investigation is another example of the failure to allow technically competent advisors to contribute. The government carefully selected personnel and orchestrated the investigation’s limited content . . . . The government controlled the writing of the report, the public hearings, and workshops conducted after the blackout. Technically competent participants were given bare minimum opportunities to comment. The government even required those involved in the investigation to sign confidentiality agreements, an action unprecedented in the history of electric power in the U.S.

Other papers expressed confidence that enforcement of existing reliability rules and making them mandatory rather than voluntary would suffice. The conferences were held in September, 2005. In July 2006, DOE quietly issued a report (with no accompanying press release) titled The Relationship Between Competitive Power Markets and Grid Reliability . No conclusions about the conflicting views on the relationships among restructuring, competition, and reliability expressed in the papers are drawn. It simply assembles and summarizes the conference white papers and public comments, without findings and recommendations. On October 3, 2006, DOE and Natural Resources Canada issued a final report on implementation of the Blackout Task Force recommendation for an independent study, saying that the "independent study" recommendation has now been fully implemented

Nothing more is to be done.

In sum, the possibility of a rigorous independent study to implement Recommendation 12 of the Joint U.S.-Canada Task Force has ended with a report that makes no findings or recommendations. Neither the U.S. - Canada Task Force, nor any state or federal utility regulator, nor any independent researchers conducted a thorough examination to determine whether restructuring contributed to the blackout of 2003 or its long duration, and whether reliability of the electric power system is now compromised in states that restructured. For more information, see PULP's web page on competition and reliability.

New FERC Rules to Impose Voltage Stability Obligations on Local Utilities

The Energy Policy Act of 2005 added a new Section 215 to the Federal Power Act to establish mandatory reliability rules for the bulk power system. This was a recommendation of the joint U.S. - Canada task force report on the blackout of August 2003. The new law requires FERC to approve an "electric reliability organization" (ERO) to develop and enforce detailed reliability rules to be adopted by FERC. The North American Electric Reliability Council, which for years had developed voluntary reliability standards and monitored utility compliance with them, created a new entity, the North American Electric Reliability Corporation (NERC), which was then approved as the new ERO.

After a NERC stakeholder process to develop detailed draft rules, NERC petitioned FERC for their approval. On October 20, 2006 FERC issued a Notice of Proposed Rulemaking (NOPR) in FERC docket RM06-16,largely adopting NERC’s proposals, but stating:

although we believe it is in the public interest to make these Reliability Standards mandatory and enforceable by June 2007, we also find that much work remains to be done. Specifically, we believe that many of these Reliability Standards require significant improvement to address, among other things, the recommendations of the Blackout Report.

Significantly, FERC modified the proposed rule on reactive power, VAR001-1. An imbalance of reactive power can cause voltage instability, equipment failure and blackouts even if the overall supply of real or active energy is sufficient. Reactive power demand increases particularly in hot weather when large numbers of utilitiy customers use air conditioners. With the breakup of New York's utilities, responsibility for providing reactive power is shared by local distribution utilities, who use static VAR capacitors in their systems, and merchant power generators, who can provide dynamic VAR supply.

According to a FERC Staff Report on Reactive Power, other restructured jurisdictions impose a duty upon generators to provide MVARS without additional compensation, while market mechanisms are being devised - and revised - in the United States. Assuring adequate reactive power (MVAR) supply at times when generators can make far more by selling energy (MW) is an issue in restructured markets in the United States, according to the FERC report at p. 7:

A generator’s cost of producing reactive power can sometimes include opportunity costs associated with forgone real power production. Opportunity costs arise because there can be a trade-off between the amount of reactive power and real power that a generator can produce. When a generator is operating at certain limits, a generator can increase its production or consumption of reactive power only by reducing its production of real power. As a result, producing additional reactive power results in reduced revenues associated with reduced real-power production.

Inadequate supply of reactive power was cited as one of the factors in the blackout of 2003, and this, in turn, has been linked with restructuring of the electric industry and fragmentation of responsibilities for reactive power in the states that experienced the blackout:

Finally, the separation into generation and transmission companies resulted in an inadequate amount of reactive power, which is current 90 deg out of phase with the voltage. Reactive power is needed to maintain voltage, and longer-distance transmission increases the need for it. However, only generating companies can produce reactive power, and with the new rules, they do not benefit from it. In fact, reactive-power production reduces the amount of deliverable power produced. So transmission companies, under the new rules, cannot require generating companies to produce enough reactive power to stabilize voltages and increase system stability.

FERC's proposed modification to the NERC proposal would explicitly impose a new federal law duty upon load serving entities, e.g., local utilities such as Con Edison, to acquire sufficient reactive power, to monitor the power factor and voltage stability in real time at distribution substations connected to the higher voltage transmission lines, and to maintain voltage stability in its interconnected distribution system. This could require load shedding to bring reactive power demand into line with the available supply, or other reactive power load management tools.

The proposed new duties of distribution utilities are a recognition by FERC that principles of physics, electricity, and Maxwell’s Equations do not follow regulatory and jurisdictional delineations between federally regulated transmission services and state regulated distribution system services. If adopted, the FERC rules will clarify future responsibilities of local utilities regarding voltage stability within their portion of the grid, acquisition of sufficient reactive power, and management of reactive power loads through load shedding or other means to balance reactive power resources and with reactive power demand.

The New York PSC filed comments objecting to the proposed definition of "bulk power system" which underlies the basis for the proposed FERC standard that would place new reactive power duties upon distribution utilities such as Con Edison. Comments of New York's transmission owners, including Con Edison, also question FERC's expansive definition of the bulk power system that would impose new duties upon Con Edison.

Was an Unscheduled Outage of a Power Plant Providing Reactive Power a Factor in Con Edison's July 2006 Queens Outages?
Con Edison has not addressed reactive power loads and voltage stability in its October 12, 2006 report on the July 2006 Queens outage. Also, Con Edison resisted PULP's discovery requests regarding communications with FERC and the ISO just prior to and during the outage that began on July 17. In the week prior to the Queens outage, FERC and NYISO officials issued broad warnings in testimony to Congress of the possibility of load shedding and blackouts in New York City in hot weather. We do not yet know if the grid officials were concerned only about a possible shortfall in active power due to transmission outages, or if there were additional concerns, for example, possible insufficiency of reactive power, or voltage instability that could directly or indirectly be due to another outage, for example, a generator tripping off line. NYISO reports indicate there was a "reserve pickup" due to a "large event" that occurred 25 minutes before a fire burned into a feeder line that began the Queens outage event. A "Reserve pickup may occur if energy becomes deficient due to the loss of a large generator...," according to the NYISO Transmission and Dispatching Operations Manual, Section 4, p. 12 - 13.

For further information, see PULP's web page on the 2006 Queens outage.

Power Outages, Utility Regulation, and New Utility Holding Company Structures

Reliability under "Performance-Based Regulation"
Recent long duration electric power outages in hot weather and slow recovery after storms have raised concerns about reliability, the level of utility investment in infrastructure, and commitment of staff and resources to preventive maintenance. These concerns may be related to the trend of state utility regulation, which has been to set "delivery" rates for several years using a "macro" approach that does not specifically review details of utility spending plans. Utilities are given great flexibility to allocate resources, cut costs and keep any savings during the term of the rate plan as profit. When the rate plan expires, another multi year plan is typically approved.

The New York PSC created statistical performance "metrics" and standards so that, ostensibly, utilities will not slash costs in areas that eventually affect service quality and reliability. The intent was to focus on "performance" and results, while reducing regulatory scrutiny of inputs, such as infrastructure investment, maintenance, and staffing levels, and giving utilities what they wanted, which was increased "flexibility." In its enthusiasm to allow utilities broad latitude to cut costs where they choose without regulatory "micromanagement" while delivery rates are frozen during long term rate plans, regular five-year detailed audits of utility plans, performance and operations - outside the ratesetting cases - apparently were abandoned by the PSC, even though they are statutorily mandated. See Con Ed Monitor a Sleeping Watchdog, indicating that the PSC has not conducted such audits of Con Edison for at least 15 years.

Under this lightened regulation, have utilities reduced maintenance, such as tree-trimming and replacement of old power poles, with a result that greater damage occurs when large storms hit? Is it now economic for a utility to risk failing the PSC performance metrics if the cost of meeting the standard is greater than the cost of failing it, or if the cost of meeting the standard would reduce earnings? In 2004, the New York PSC reviewed the advent of performance regulation, and suggested that public safety may have been compromised under the regulatory policies that rely more on utility choices in an order regarding the investigation of an electrocuted pedestrian in New York City:

"Over the past 10 to 15 years, we and other regulatory commissions across the nation have moved from traditional one-year litigated rate cases to multi-year performance-based rate plans. The purpose of these plans is to allow for rate stability while allowing the utilities greater flexibility in managing their operations. Staff’s investigation into this matter suggests that the utilities may not have been placing enough attention and emphasis on safety matters."

A 2004 PULP report indicates that for several years, Con Edison had set a lower budget each year for certain preventive maintenance programs, and then each year underspent the budget. For example, maintenance budgets and expenses significantly declined from 1999 - 2003 in the Brooklyn-Queens division, which includes the areas that experienced lengthy outages in the summer of 2006.

Negative rate adjustments when a utility fails to meet performance standards have not been swiftly implemented by the PSC when the performance standards are not met. Instead of a prompt downward adjustment or refund to customers, rate reductions have been "deferred," to be taken into account in a future rate case when calculating rates for future years.

For example, Con Edison failed to meet reliability standards in 2002. A 2003 PSC order said the company was "directed to defer $7.5 million in shareholder funds on its books for the benefit of ratepayers, use of such deferral to be determined at a later date."

Ultimately, this credit for ratepayers was amortized, along with others, over three years beginning in 2005. The impact of the delayed reliability performance adjustment for 2002, now being amortized from 2005 - 2008, is insignificant in the context of the 2005-2008 rate plan, where sums much larger than the deferred rate adjustments for poor reliability performance were compromised in the final joint proposal for settlement of the case.

Why would the PSC allow the financial impact of performance failures be so disconnected from the time of failure, delayed, and then diffused over years in the next rate case?

Some utilities have argued that the PSC cannot impose performance based rate reductions without hearings and without following statutory procedures for the imposition of penalties under Section 25 of the Public Service Law. Section 25, which was enacted before modern administrative law and procedure was developed, requires court proceedings for the PSC to impose financial penalties for failure to obey a law, rule, or PSC order. It is unclear whether the PSC could require a set of reliability performance criteria and impose adverse financial consequences for failure to satisfy them without following the antiquated and cumbersome procedures of Section 25.

This lack of legislative clarity may be a factor in the rather weak reliability performance plans, all of which have been agreed to by utilities in the context of their rate case settlements. A lack of real teeth in the form of prompt and significant financial consequences for a utility failure to provide safe, reliable and adequate service is not unsurprising. Ultimately, the sanctions for poor performance in the rate case settlements have all been acceptable to the utilities.

There should be a full investigation whether reliability has been impaired as a result of the relaxed PSC oversight, whether the PSC "performance metrics" actually and accurately measure the right things to assure reliability and adequacy of service, whether economic consequences to utilities of not attaining existing performance targets set by the PSC are really sufficient, and whether the power of the PSC to impose prompt, meaningful rate refunds or reductions in response to objectively measured failure to provide reliable service needs to be clarified or bolstered by the legislature.

Have New Holding Company Structures Affected Utility Infrastructure Investment Decisions?
Apart from "performance regulation," another factor influencing utility investment in infrastructure is their new corporate structure. Previously, financial choices were rather limited for local utilities: profits basically were paid out as dividends to shareholders or reinvested into the utility infrastructure. Money raised by the sale of stock or issuance of bonds generally had to be invested in the utility operations.

New holding company structures were encouraged by lax SEC enforcement of the federal public utility holding company act (PUHCA), which eventually was repealed in 2005, and by the New York PSC, when it attempted to "restructure" New York's electric industry in 1996-97. Now New York utilities send their profits to their holding company parents, and the proceeds of new stock and bonds issued by the holding company parent, even though primarily based on the assets and operations of the state regulated utility, can be spend on activities of other ventures withing the holding company structure.

For example, the holding company parent corporation may buy utilities in other areas, states or countries, as National Grid has done, or may enter into new lines of business through less regulated subsidiaries, as Enron did and as Con Edison has done.

As a result, the holding company parents now can allocate the capital earned from New York regulated utility to investments, or raised by issuing new stock and bonds, in other areas and activities where they believe greater returns for shareholders can be realized. Some states are now considering enactment of their own utility holding company laws to refocus utilities on the provision of reliable local service at reasonable rates.

RG&E Tightening Collection Policies

Rochester Gas & Electric (RG&E) may be tightening its collection practices for customers in arrears who are threatened with termination of their electricity or natural gas service. An August 2006 news report indicated that the company in the past had restored service with a partial payment from the customer, without the customer having entered into a formal written deferred payment agreement (DPA). An October 2, 2006 news report indicates that a new policy is in effect that will require customers who do not pay arrears in full to enter into DPAs as a condition of service continuation.

Nothing has changed in the law governing situations where customers in arrears face possible termination of service for nonpayment. The Home Energy Fair Practices Act (HEFPA) implements New York State's policy of continuous utility service for residential customers to advance the public health and welfare. See Candle Fires: A Symptom of "Rolling Blackouts" Affecting Low-Income Households.

HEFPA requires a utility to provide advance notice of termination and to offer customers in arrears the opportunity to pay them in installments. The utility typically offers the customer a "standard" repayment agreement: this involves a substantial "down payment" to defray part of the arrears and a schedule of monthly payments to pay the balance. The arrears payments must be made along with timely payment of bills for current service. When a DPA is in place, and payments are made on time, late payment charges cannot be assessed.

The "standard" DPA is really the first offer from the utility. Customers must be notified by the utility that they may negotiate the terms of a DPA - both the "down payment" and the monthly installment amount -- based on their individual financial circumstances.

PSC regulations require utilities to bargain in good faith over the terms of DPAs to as little as nothing "down" and $10 per month toward arrears (a "minimum DPA"), depending on the customer's ability to pay. Section 43(2) of HEFPA provides that if agreement cannot be reached customers may obtain a decision on the terms of a DPA from the Public Service Commission.

A customer who breaks a "minimum DPA" is then subject to termination of service. A customer who breaches a DPA for more than the minimum is subject to termination unless there has been a change of financial circumstances since entering into the agreement.

The HEFPA statute requires DPAs to be signed by both the company and the customer.

Over the years companies have entered into unwritten agreements with customers without the formality of a written DPA. A customer who breaks an unwritten promise to repay (typically made on the phone) should still be able to get a written DPA.

If customers cannot reach agreement on a DPA -- or if there are other issues relating to denial or termination of electric or natural gas service, including medical emergencies -- they may call the PSC Emergency HOTLINE, 1-800-342-3355 between 7:30 a.m. and 7:30 p.m . on business days for PSC staff assistance.

Customers who have exhausted their remedies under HEFPA with the utility or the PSC may be eligible for assistance under the Home Energy Assistance Program (HEAP). The HEAP program for 2006 - 2007 will open in November 2006. Other public assistance or a loan under section 131-s of the New York Social Services Law may be available from local departments of social services if a customer is threatened with termination of utility service, or if service has been terminated.

For further information, contact PULP or check PULP's website Help Center.