FERC Adopts Electricity Transmission Siting Rules: Says it Can Reverse State Denials

In Section 1221(a)of the Energy Policy Act of 2005, Congress for the first time enabled the federal government to approve the siting and location of new electric transmission projects. The new law required the Department of Energy (DOE) to issue a national transmission congestion study for comment by August 2006, and every three years thereafter. Based on its study and public comments filed in response to it, DOE may designate selected geographic areas as "National Interest Electric Transmission Corridors."

Applicants for electricity transmission projects proposed within the DOE-designated "corridors" that are not acted upon by state siting authorities within one year may request FERC to exercise federal "backstop" siting authority.

The Federal Energy Regulatory Commission (FERC) issued new rules November 16, 2006 to implement the new law. In a statement issued with the new rules, FERC Chairman Kelliher stated

The final rule also clarifies the meaning of the term “withheld approval” in the statute. As indicated earlier, one of the circumstances where FERC is authorized to issue a construction permit for a transmission project in a designated corridor is where a state siting body has "withheld approval"” for a year. The question has arisen as to whether than term only means state failure to act, or means both state failure to act and denial. We interpret this term using the usual rules of statutory construction, and conclude the most reasonable interpretation is that the term encompasses both state failure to act and denial.

In dissent, Commissioner Suedeen Kelly said the new rules go too far. Under her reading of the words of the statute, the power of FERC to approve a project comes into play only if a state fails to act on a transmission siting proposal:

States have always had exclusive, plenary jurisdiction over transmission
siting.... In 2005, Congress passed EPAct, which, for the first time, carefully carves out a limited role for the federal government in the area of transmission siting. EPAct amended the FPA [Federal Power Act] to give the Commission the authority to site electric transmission facilities in five specific situations.... The majorityÂ’s interpretation of Section 216(b)(1)(C)(i) would add a sixth situation: the Commission would have jurisdiction to approve the siting of a transmission line pursuant to federal law where the State has lawfully denied an application pursuant to state law.

In Commissioner Kelly's view, if a state acts on a proposed project within a year, and denies the project, there could be no overriding federal approval. Thus, the effect of the statute would be to encourage prompt action by states on often controversial transmission projects, and a state that wants to retain its full powers over transmission would be able to do that if it handles project applications expeditiously.

Given the likelihood of litigation over siting of transmission projects, the FERC majority view - that it can approve projects rejected by a state - will probably be tested in the courts, with the Supreme Court having the last word. Or, Congress may amend and clarify the law, giving new and clearer instructions to FERC for its implementation.

Meanwhile, DOE issued its first transmission congestion study on August, 8 2006. It found "critical" congestion areas in "the Atlantic coastal area from metropolitan New York southward through Northern Virginia." DOE did not, however, designate any "national interest transmission corridors." On November 9, 2006, DOE issued a press release announcing the opportunity for further comments on its 2006 study.

Update
February 18, 2009 -- Federal Appeals Court decision rejects FERC's assertion of override authority.

APPA Study Debunks NY PSC Report on Electric Restructuring

In March 2006 the New York Public Service Commission issued a Staff Report on the State of Competitive Energy Markets lauding the claimed results of its efforts to restructure New York state's wholesale and retail electricity industry. A new study undertaken for the American Public Power Association (APPA) examines the methodology of the New York PSC report and other reports that have attempted to measure costs and benefits of restructuring. With respect to the New York PSC report, the APPA report states:

In summary, the intention of this staff report of the New York State Department of Public Service seems not to be a careful or balanced assessment of the issues. Rather, it is at best an update on changes in the electricity (and gas) markets in New York and in state policies affecting these markets. Even as an update, however, it pays inadequate attention to causation and precision in its evidence and claims.

NY Court of Appeals Says PSC "Lightened Regulation" of New Electric Companies Justifies Local Property Tax Reductions

The New York PSC's "Light Regulation" Regime for New Electric Companies
In the 1990's heyday of electricity deregulation championed by Enron, 15 state legislatures authorized "restructuring" of their electric industries. In contrast to legislative action in other states, the New York PSC engineered the voluntary divestiture of utility power plants to new utilities through a series of agreements and orders. Retail utilities like Con Edison agreed to sell nearly all of their power plants to new companies. As a result, far more electricity must now be purchased in wholesale markets to serve retail customers. Typically these purchases are made at "market-based" wholesale rates under the jurisdiction of the Federal Energy Regulatory Commission (FERC). Residential and industrial customers have protested FERC's market rate regime, in which the benefit of the lower cost electricity from more efficient or depreciated power plants no longer flows to consumers. Today, the benefit of lower cost energy, say, from hydro, nuclear, or coal plants is reaped by wholesale utilities with "market-based" rates who are allowed by FERC to charge rates based on the price demanded by the most expensive plant running at any given time.

The New York PSC's "Realistic Appraisal" of Which Laws to Enforce
In granting certificates to the new electric companies, the PSC purported to waive many statutory requirements. The PSC asserted that it could make a "realistic appraisal" of which of the many laws applicable to electric companies, passed over the last 100 years by the legislature, should now apply to new owners of divested power plants. The PSC issued "light regulation" orders for each of the new companies, and in doing so, an alternative regulatory regime was created by PSC orders. See PULP's summary of PSC restructuring orders.

The "light regulation" orders purport to lift the PSL Section 65 utility obligation to provide safe and adequate retail service at reasonable rates to customers upon the customers' demand. They are premised upon assertions that the new electric companies intended to sell only at wholesale. It is an open question whether in the future, in recognition of the malfunctioning FERC-supervised market rate regime, the PSC could make a new "realistic appraisal" and require the new utilities to make some or all of their output available for the benefit of retail customers at reasonable cost-based rates.

Leveraging PSC "Light Regulation" Orders Into Local Property Tax Reductions
Armed with a "lightened regulation" decision of the PSC, a new electric company that bought a power plant from an older utility, Con Edison, sought to reduce its New York City property taxes. The relevant state law, Section 1801(c) of the New York Real Property Tax Law, establishes categories of taxation, and allows higher taxes upon PSC supervised utilities than upon companies engaged in general commercial activities. This higher taxation of utility property could be due to the heavy impact and burdens placed upon local land use and air quality by polluting power plants.

The definition of "utility" property in the tax law is:

c) "Utility real property" for the purposes of this article means the real property, including special franchises, of persons and corporations subject to the supervision of the state department of public service, the state department of transportation, or any other regulatory agency of the state or federal government, used in the generation, storage, transmission, distribution or sale of gas, electricity, steam, water, refrigeration, cable television, telephone or telegraph service, delivered through mains, pipes, cables, lines or wires, provided, however, that "utility real property" shall not include the types of real property, property or land described in paragraph (a) or (b) of subdivision twelve of section one hundred two of this chapter owned by such persons and corporations.

The section 102(12) (a) and (b) property excepted from the definition is ordinary land and buildings. The "utility real property" tax classification thus turns on whether the company is "subject to the supervision of the state department of public service . . . or any other regulatory agency of the state or federal government."

There can be no doubt that electric companies are under PSC "supervision." Electric companies are broadly defined by the New York Public Service Law 2(13) to include companies owning electric plants, and the PSC is broadly charged by the legislature with the power and duty to oversee all electric companies in PSL section 5:

§ 5. Jurisdiction, powers and duties of public service commission. 1. The jurisdiction, supervision, powers and duties of the public service commission shall extend under this chapter . . . .
b. To the manufacture, conveying, transportation, sale or distribution of gas (natural or manufactured or mixture of both) and electricity for light, heat or power, to gas plants and to electric plants and to the persons or corporations owning, leasing or operating the same.

The PSC "lightened regulation" orders held that all of the new companies that bought power plants from the older utilities are "electric companies" with "electric plants" as defined in Public Service Law 2(12 and (13).

A new utility's attempt to challenge its tax status as a "supervised" utility and thus escape the "utility real property" tax classification would seem to be a "no-brainer" in favor of the taxing authority, and indeed a lower court rejected the effort. But when the issue came to the Appellate Division and then to the state's highest court, New York Court of Appeals, in Matter of Astoria Gas Turbine Power, LLC v. Tax Commission of City of New York, the new electric company (AGTP) was found not to be sufficiently "supervised" by the PSC to warrant its continued taxation in the "utility" classification. Thus, the PSC's restructuring and its decision not to exercise its full powers over the new electric company leveraged a local property tax reduction. As a result, power plants must now be taxed in the same category as general commercial businesses.

While flawed in its analysis, the decision is quite interesting in its misapprehension of the PSC's restructuring. The Court said

"During the past three decades, both Congress and the New York State Legislature have sought to deregulate the electric utility industry."

Actually, while utilities continue to clamor for deregulation, neither Congress nor the New York Legislature actually "deregulated" the electric industry. To be sure, Congress and the New York Legislature at times have sought to induce competition, but the new utilities, including the petitioner in the Court of Appeals case, have not been "deregulated," and they are generally subject to the same laws as the traditional utilities. For example, the core principles of the Federal Power Act and the state Public Service Law that require publicly filed rates subject to review for reasonableness have not been changed. To the extent "deregulation" has occurred, it has been due to FERC or PSC forbearance and decisions not to enforce statutes that remain on the books.

The Court of Appeals sought to distinguish the new electric company owning the power plant sold from the traditional utility, stating:

traditional public utilities are generally afforded certain economic advantages. For instance, public utilities have historically exercised monopoly power, protecting them against competition. In addition, public utilities typically are afforded governmental franchises permitting them to place equipment on public rights-of-way or otherwise use public land. Given public utilities' competitive and financial advantages, the PSC establishes rates at which they can sell their product.

Much of the rationale for FERC and PSC approach to longstanding statutes rests upon the fallacious reductionism reflected in the court decision, i.e., the only reason for regulation is to protect consumers from monopoly providers, so the statutes can be disregarded if multiple providers appear. This, however, is a spurious distinction: nowhere in the Public Service Law does the word "monopoly" occur. The rationale for PSC regulation of electric service and supervision of electric companies is that electric service is a public service and the public interest is affected. It makes no difference whether the service is provided by a monopoly utility or multiple utilities. Actually, when the New York Public Service Law was first enacted, there were hundreds of electric companies and some of them competed in the same localities without local exclusive franchises, which emerged later.

The Court of Appeals' decision posits that the same plant could be taxed higher in the past when owned by a traditional utility only because of the benefits of PSC rate regulation, and that should be changed because the wholesale prices of the plant are no longer supervised by the PSC:

In fixing a public utility's classification for tax purposes, RPTL 1802(1) and 1801(c) take into account that the public utility is virtually guaranteed to earn a reasonable rate of return. In light of the economic advantages afforded to public utilities, New York's tax scheme has treated them differently than other types of entities.

The premise that because the new utilities are "competitive" they cannot pass through their costs, including their taxes, is fallacious. Most wholesale utilities voluntarily choose to sell at market rates under FERC jurisdiction, rather than file cost-based rates or at retail under PSC jurisdiction. When they are found to have market power or manipulate markets, then they file cost-based rates. They are free, however, at any time to file cost based wholesale rates with FERC, or cost-based retail rates with the PSC, and to include their local property taxes as a cost in calculation of the rates when the file or change them. Apparently, they do not choose to file cost-based rates because their opportunities to receive greater revenues are higher with market rates . Also, one would assume that when purchasing the power plant the buyer knew what the taxes were, and had a business plan that would enable it to recover its operating costs and investment and a profit. The tax reduction is simply a windfall, particularly for power plants with low production costs whose market rates are often set by sellers with more expensive power plants.

The court decision says that fully regulated utilities are "virtually guaranteed" to earn a reasonable return. That was never the legal standard: utility rates are set to give only a fair opportunity to earn a reasonable return. There are instances in which regulated utilities fail to earn their allowed returns on capital investment, or in which their investment costs or operating expense claims are disallowed in whole or in part for being excessive, unreasonable or imprudent. When the power plant was owned by a fully regulated utility, the utility was at risk of competitive pressures that could result in "stranding" of utility investment without recovery from ratepayers if, for example, the plant was inefficient and did not run.

The Court rested its decision on a fallacious distinction between the new and old utilities:

Unlike a utility, AGTP is not assured a reasonable rate of return, but is at the mercy of volatile competitive market forces based on supply and demand. Further, AGTP possesses no governmental franchises or property interests in public streets. Thus, in conformance with the Legislature's initiative to deregulate the electric utility industry, AGTP is a competitive entity like those whose real property is properly placed in class four."

Of course, the court offers no citation to any statute reflecting "the Legislature's initiative to deregulate the electric utility industry" because there is no such law. Also, the Court's analysis does not consider the possibility that a new "lightly regulated" company might someday choose to sell at retail, and could file retail rates with the PSC subject to PSC review, or cost-based wholesale rates at FERC. Under those scenarios, the new utility could avail itself of all the perceived advantages of rate regulation.

The tax statute quoted above plainly provides for utility tax treatment if the company is subject to supervision by the PSC "or any other regulatory agency of the state or federal government. The utility in the case was under FERC rate supervision. According to a siting board decision," AGTP is wholly-owned by NRG Northeast Generating, LLC, which is held 50% by Northeast Generation Holding, LLC and 50% by NRG Eastern, LLC; the latter two companies are whollyowned by NRG." NRG Energy, Inc. is a utility subject to FERC regulation, as NRG acknowledges in its SEC Annual Report for 2005:

Federal Power Act. The FPA gives FERC exclusive rate-making jurisdiction over wholesale sales of electricity and transmission of electricity in interstate commerce. Under the FPA, FERC, with certain exceptions, regulates the owners of facilities used for the wholesale sale of electricity or transmission in interstate commerce as public utilities. The FPA also gives FERC jurisdiction to review certain transactions and numerous other activities of public utilities. . . . Public utilities under the FPA are required to obtain FERC’s acceptance, pursuant to Section 205 of the FPA, of their rate schedules for wholesale sales of electricity. All of NRG’s non-QF generating companies and power marketing affiliates in the United States make sales of electricity pursuant to market-based rates authorized by FERC. FERC’s orders that grant NRG’s generating and power marketing companies market-based rate authority reserve the right to revoke or revise that authority. . . . If NRG’s generating and power marketing companies were to lose their market-based rate authority, such companies would be required to obtain FERC’s acceptance of a cost-of-service rate schedule and would become subject to the accounting, record-keeping and reporting requirements that are imposed on utilities with cost-based rate schedules.

The court decision does not address the fact that wholesale sellers of electricity are subject to the supervision of FERC and that NRG could, if it chose to do so, or if required by FERC as a result of market rate revocation, file cost based rates that include local taxes as part of the cost of service, just as Con Edison could have done when rates for electricity from the plant were under PSC jurisdiction.

The decision only partially quotes the relevant statute and completely omits the portion of the statute which defines "utility" property as being subject to supervision of the PSC " or any other regulatory agency of the state or federal government." As a result there is no mention of the fact that the seller is still subject to full FERC supervision of its rates. That FERC has allowed companies, at their option, to seek market rates in no way diminishes the ability of the utilities to set cost based rates that will cover their expenses, including local property taxes.

In sum, this seriously flawed decision represents a victory for the new "lightly regulated" electric companies and a defeat for local taxing authorities. As a result, localities that accepted power plants and taxed them as utility property will not be able to impose taxes higher than if they were a supermarket or other commercial establishment having less environmental impact. The victory could be temporary, however, if the tax law definitions of "utility real property" and regulatory "supervision" are redefined by the New York legislature to close the loophole carved out in the AGTP case.

Recognition of Continued PSC Regulation Regarding Safety, Reliability, Infrastructure Improvement and Market Power
In an interesting turn, despite its finding that the new utilities are not "supervised" by the PSC, the Court recognized that

the PSC maintains "light regulation" over AGTP covering "matters such as enforcement, investigation, safety, reliability and system improvement . . . . This light regulation also gives the PSC authority to limit AGTP's power in the market and any actions in contravention of the public interest.

Although labeled "light regulation," these are very major matters affecting the public interest that remain subject to PSC "supervision." Over time, the decision may be overruled by the legislature to restore utility tax classifications, and its broader implications may be seen as judicial recognition that despite claims of "deregulation," the new wholesale electric companies remain subject to PSC regulation regarding matters other than their FERC-supervised rates. This is significant because the new electric companies have contended they are free to withhold their power from the market or shut down completely, for economic reasons which may include perpetuation of shortages and maintaining higher prices for other plants in their fleets.

The recognition that the PSC has oversight over market power of the new utilities is especially significant. When the old utilities divested their power plant fleets, the plants were sold to a relatively small number of companies which may be able to exert market power and maintain unreasonably high prices. As more is learned about the operation of the NYISO spot markets, and if, as is widely expected, the wholesale power generation sector consolidates further through mergers in the coming years, the Court of Appeals' recognition the New York PSC has power to review market power may become more important than the property tax break it upheld. For example, the decision could support PSC review of behavior of sellers in NYISO markets, disapproval of mergers, or conditioning mergers upon a requirement that electric companies sell only at cost-based rates.

Updates
Chuck Bennett, Shocking and Tricky Power Play: Firms Call Selves Factories to Finagle Tax Break, N.Y. Post, April 6, 2011

Hannah Northey, New York City and FERC Square Off, E&E Reporter, April 4, 2011

David Seifman and Bill Sanderson, Mike to rate-$lapped NYers: Turn down A/C, N.Y. Post, April 2, 2011

William Pentland, New York City's Electricity Prices May Double by 2014, Forbes, April 4, 2011

Devlin Barrett, Electricity Reversal Sought, Wall Street Journal, April 2, 2011 ("the expected hike in power bills . . . was first reported in the New York Post").

Bill Sanderson, New York Electric Bills to Soar 12%, N.Y. Post, April 1, 2011.

NYISO Compliance Filing, March 29, 2011, ("The NYC Demand Curve included in the compliance filing reflects the addition of property taxes. Consistent with the findings reported in the NYISO Demand Curve Report,12 inclusion of property taxes results in a 41% increase in the NYC Demand Curve.)"

FERC Order Accepting Tariff Revisions Subject To Modification, Suspending For Five Months, And Directing Compliance Filing, Jan. 28, 2011("Property taxes are legitimate costs that are normally included the cost of new entry; NYISO has not shown that they will not be incurred by
peaking units that will be constructed in New York City....Accordingly, because of the questionable eligibility of a peaking unit and the fact that such abatement is discretionary, we direct NYISO to exclude tax abatement from the calculation of net CONE for NYC").

Yertle the Turtle? AT&T Now "Two Mergers Away" from Reintegration

AT&T was divided into seven regional bell operating companies (RBOCs) as a result of protracted antitrust litigation that ended in the 1980's. The RBOCs basically were confined to local phone service and they were barred from the lucrative long distance business, where AT&T was to compete with newer long distance service providers such as MCI.

The goal of promoting competition, however, now seems more distant. In the Telecom Act of 1996, Congress allowed the RBOCs to re-enter the long distance business if the FCC found that the industry was competitive. The RBOCs were granted permission by the FCC to re-enter the long distance business, resulting in the demise of the newer and smaller long distance companies.

Instead of competing against one other, the RBOCs merged with other RBOCs (e.g., NYNEX and Bell Atlantic merged to form Verizon), and now the merged RBOCs are acquiring smaller companies and former long distance competitors (e.g., Verizon's acquisition of GTE and MCI).

Now, AT&T, the once broken-up monopoly, is merging with SBC, a large RBOC.

UTEX Communications Corporation, a disgruntled small competitor using voice over internet protocol technology (VOIP), in comments filed with the FCC, analogizes AT&T to Dr. Seuss' Yertle the Turtle: "I’m figgering on biggering and BIGGERING and BIGGERING and BIGGERING.” According to UTEX, "[w]e are only two mergers away from re-vesting AT&T with its old empire...."

Meanwhile, local phone competition from companies leasing wholesale network elements from the RBOCs is dying as a result of FCC and court decisions. Nevertheless, the New York PSC continues to deregulate more of Verizon's local service, despite Verizon's dominant position. This is being done on the ground that "intermodal" competition between alternative phone technologies such as cable and wireless justifies dispensing with regulation. The New York PSC erroneously assumed the only reason for regulation was the monopoly nature of phone service. Regulation exists not because of the number of providers but because of the importance to society of universal communications services at just and reasonable rates, no matter who provides it.

Today's local phone choices really boil down to two sources, cable and telephone. VOIP services still must go over a phone line (DSL) or a cable line to the home. A duopoly dividing the consumer market between a dominant phone company and a cable company is hardly likely to result in competitive prices and services over time. Once market shares are established, the companies are likely to have monopoly prices and not to undercut one another.

Wireless phone service is sometimes claimed to be additional competition to cable telephone service, justifying less regulation of Verizon. But wireless service is not a full substitiute for landline service, and in any event, Verizon is the major wireless provider in New York state. In opposition to relaxed regulation of telephone companies based on "intermodal" competition, PULP submitted comments showing that in recent years New York has lost ground in its effort to achieve the goal of universal telephone service.Telephone availability in low income households has declined. PULP recommendations that measures be taken to increase affordability of service through reform of the federal-state telephone Lifeline program were rejected by the New York PSC. Now there has been a steep reduction of participation in the lifeline rate program due to overly stringent eligibility requirements and defects in administration of the automatic enrollment program.

Also, Verizon is rapidly acquiring local cable franchises to provide television service in New York, in competition with cable. To the extent Verizon succeeds in replacing cable TV service, the availability of cable telephony as a competitor is reduced.

The Telecom Act of 1996 also adopted new measures to promote universal service, affordability, broadband service to rural and inner city areas, lifeline and link-up service, and broadband for schools and libraries across the country. The results in these areas are also disappointing. For example, the number of New York households without access to any phone service is going up, and the number of low income households receiving lifeline discount service has declined by more than 200,000, effectively raising their rates by more than $24 million per year. For more information, see PULP's web page on universal service.

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.

Think Twice Before Switching Utilities

In 1996, the New York PSC adopted a utility "restructuring" paradigm prominently championed by Enron. Under that model, customers could deal with two utilities for electricity and possibly two more utilities for natural gas. The traditional utility, in that model, would stop selling electricity and gas, which would then be sold only by lightly regulated new "energy services companies" or "ESCOs." Enron wanted to be a major player in these new wholesale and retail markets.

This method of deregulation, described in "Disconnected Policymakers," created a synthetic competition. New wireless electric and pipeless natural gas utility middlemen would buy electricity and natural gas in wholesale markets and sell in deregulated retail markets, and the rates, terms and conditions of their service would no longer policed closely by federal or state regulators. This system was being considered in many states until the Enron bankruptcy debacle. Notwithstanding claims of utility deregulation proponents, serious studies have found no discernible consumer benefit in the states that "restructured" their utilities, several states that went down the road of utility deregulation reversed course, and others are reconsidering their decision.

Few residential customers in New York switched to ESCO service. Yet, over the past decade, the New York PSC has required many millions of dollars of ratepayer and taxpayer funds to be spent to promote migration to ESCO service. There is no analysis, however, showing that customers save money or receive different or superior service with ESCOs. Instead, the emphasis has been upon expensive PSC and utility advertising campaigns (paid for by utility ratepayers) and promotional gimmicks, such as small discounts for a limited period. These campaigns typically extoll the virtues of "choice" but are short on information on price and service.

In 2002, the legislature overruled the PSC by enacting the Energy Consumer Protection Act which requires ESCOs to follow HEFPA, the Home Energy Fair Practices Act. Even so, the PSC may be upholding unfair provisions in ESCO contracts. Small business customers have no HEFPA protection and they lose the protection of the non-residential customer protection rules when they switch to ESCOs. When customers discover that prices are far higher than the old utility, they may find that their ESCO contract contains very expensive early termination provisions.

In 2006, the PSC geared up its efforts to require all utilities to implement an "ESCO referral" program in which participating customers are assigned randomly to ESCOs. They will receive a small discount on the commodity part of their bill for two billing periods, and then be shifted to ESCO rates unless they take action to return to full utility service from the traditional utility. Typically ESCO rates, terms and conditions of service for the time after the introductory period are not disclosed at the time the customer decides to participate in the program. PULP objected to many aspects of this program in the ESCO marketing guidelines case. The PSC rejected PULP's arguments in its order approving the guidelines for ESCO referral and in its September 26, 2006 order denying PULP's petition for clarification and rehearing.

Utilities are continuing ESCO service marketing promotion, including elaborate "energy fairs" and advertising campaigns whose cost is charged to utility customers. Door to door sales abuses, high pressure and misleading sales practices have been reported. AARP has cautioned utility consumers to be wary of the program. PULP's website page on ESCO issues also has information about ESCO service and questions and answers for energy shoppers considering ESCO service.

Did Hedge Fund Attempt to Corner the Natural Gas Market for March 2007?

Amaranth, a "hedge fund," lost more than $6 Billion in its natural gas investments and 65% of its value in September 2006. McCullough Research asks the question, "Did Amaranth Attempt to Corner the March 2007 NYMEX at Henry Hub?" in a report issued September 26, 2006, and says

we think that Amaranth was a situation waiting to happen, given the lack of federal oversight of energy markets by FERC and the CFTC. Although some pundits assert that “the market” is strong enough to absorb Amaranth’s ripple, we are deeply concerned that a single, somewhat small hedge fund in effect may have attempted to corner the natural gas market.

The report attempts to estimate the huge trading positions that appear to have been necessary for Amaranth to have incurred such large losses, which far exceeded the amount needed to control the market price for natural gas in March - April 2007. Based on the little data that is available, McCullough concludes Amaranth's trading positions were consistent with a strategy to "corner" the natural gas market and demand monopolistic prices at a time when the amount of stored gas is lowest and the market is most vulnerable to manipulation.

The report also discusses the impact on consumer prices, rebutting the notion that this was simply a financial matter involving trading and speculation that did not affect prices. It highlights the continued lack of regulation of energy futures markets by FERC and CFTC due to exemptions won by Enron, and the need for effective market regulation.

Robert McCullough was one of the first analysts to identify market manipulation in the Western electricity markets in 2000 - 2001 at a time when officials were still claiming the California electricity price spikes and shortages were due to supply and demand rather than withholding of supply and market manipulation.

NYISO Costs Skyrocket, Benefits Questioned

From Power Pool to ISO
The New York Power Pool (NYPP) was formed in 1966 to coordinate the state's electric power grid after the 1965 major blackout in New York City. By agreement of its member utilities (seven investor owned utilities and the New York Power Authority), NYPP dispatchers issued orders to control which generators run at any given moment. This was intended to balance generation with the demand of customers for electricity at least cost, consistent with reliability rules designed to minimize the probability of blackouts by maintaining adequate reserves, consistent voltage and stable frequency in the bulk power grid.

The New York Public Service Commssion's 1996 "vision order" invited vertically integrated utilities to divest their power plants and form new holding company structures, and urged formation of a new entity, the "New York Independent System Operator" (NYISO), to adjust power production to meet demand and to set uniform prices for the merchant generation sector.
The NYPP was transformed into the NYISO in 1999. The NYISO was certified by the NY PSC as a non profit electric company, and FERC approved its tariffs. The NYISO took on the new role of managing wholesale spot markets for energy and ancillary services in the state. Rather than dispatch generation based on utilities' cost of production, as the NYPP had done, the NYISO dispatches power based on sellers' spot market"bids," or prices demanded which need not be related to costs.

The Federal Energy Regulatory Commission (FERC) approves the NYISO tariffs and market rules for setting wholesale spot market rates of market participants -- a subdelegation of its powers to a private utility not directly accountable to the public. FERC also allowed most sellers of wholesale electricity in New York to dispense with advance public filing of all their rates, allowing them to change rates daily and hourly, and to demand what the market will bear in bids kept secret under the NYISO market rules. NYISO rules allow sellers to offer the output of power plants in segments priced so as to withhold a portion from the market, and to triple their rates, based on prior bids.

FERC allows sellers to have market rates based on assessment of each seller's individual capability to move the market, without regard to evidence that sellers lacking individual market power can achieve monopolistic results in the auction markets run by the NYISO. FERC has a rule against "market manipulation" but that does not bar strategic bidding.

Higher Prices in Uniform Clearing Price Auctions
Since the advent of the NYISO, New York electricity prices have risen substantially. When costs of fuel, notably natural gas, rise, electricity prices rise too because in many hours of the day natural gas fueled power plants are called to run. Under the NYISO uniform clearing price system all sellers are paid the same price regardless of their costs. As a result, sellers can obtain prices at the NYISO based on bids of natural gas power plants, even if their plants use cheaper coal or other fuels and can produce electricity at far lower costs. As a result, much of the value of lower cost energy in the state generated from from hydro, nuclear, and coal now goes to the merchant generation sector and energy traders rather than to consumers. When those plants were owned by the retail utilities, the cost of the plants was depreciated and over time customers would pay only for the running costs and an allowance for remaining undepreciated costs. Now the divested power plants are in the merchant generation sector, and have higher values because of the higher prices available in the NYISO markets.

Higher Prices Through Strategic Bidding
Deregulation proponents often claim that energy spot market sellers would offer their service at their operating costs. By doing this a seller would never lose money when they run and they would benefit whenever another (more expensive) producer clears the market and sets a higher price that is paid to all.

But even if paying all sellers the system marginal cost of generation were a good idea - a debatable proposition - that is not being achieved in the ISO markets that pay the marginal bid.

Mathematical game theory analysis has demonstrated that repetitive auction markets such as those run by the NYISO are gamable even if no single seller has the power, acting alone, to drive prices up. A "Nash equilibrium" can be reached in which participants in the repetitive auctions mutually learn to increase their profits and achieve oligopolistic pricing results without overt manipulaiton or collusion.

For example, if multiple sellers utilize "hockeystick" bidding tactics by offering their output in "blocks" with higher prices as more is sold, this collectively withholds power and drives prices up. FERC has approved such bidding practices.

Shortly after the NYISO began, staff of the NY Department of Public Service issued a Draft Report finding that NYISO markets are not competitive and are vulnerable to abuse, due in part to the exercise of market power by sellers. PULP filed comments urging public disclosure of the sellers' costs so it could be determined if sellers were gaming the market by strategic withholding or otherwise not bidding their output at cost.

No "final" report was issued by the PSC. Sellers' price demands are still filed secretly at the NYISO instead of publicly at FERC, as the plain language of Federal Power Act Section 205 requires. Sellers' bid data that is released by the NYISO is more than six months old and does not identify sellers.

The NYISO has engaged in continuous revision of its market rules, but they do not requre public filing of rates demanded and do not require disclosure of costs to determine if bids are excessive. The NYISO retains a "market monitor" consultant who issues annual reports which uniformly assert that sellers are, in general, not manipulating the NYISO spot markets. The tests used by the NYISO market monitor are not designed to detect hockeystick bidding or other strategies that result in higher market clearing prices.

Higher Prices for Capacity Payments to Existing Generators Did Not Induce Building of New Generation Plants or Transmission Lines
In an effort to substitute market mechanisms for energy planning, NYISO created a capacity market which now pays existing power plant owners more, through capacity payments, to induce the creation of additional power plants by them or others, with no commitment, however, that the recipients of the payments actually build power plants. In NYISO's comments on an August 2006 DOE transmission study it is claimed that

NYISO’s markets have had considerable success in attracting investment. Approximately 2,143 new Megawatts (“MW”) of generating capacity was built in New York City from 1999 to 2005.

It might be more accurate to state that the new generation resources have been created after the failure of NYISO capacity markets.

A closer look would find that of the 2,143 MW of new generation built in New York City since the advent of the NYISO, most of it was due to reliance on government and the traditional local utility, and not in response to the capacity charges paid to existing generators and added to customer bills.

For example, the New York Power Authority built a number of small gas turbine power plants totalling 450 MW. This was done to avert an impending price and supply crisis that became apparent in the summer of 2000 - the first summer of the NYISO's existence - when electricity prices in New York City soared 43% despite it being a cool summer. The Power Authority states

We had launched a crash program in late August 2000 to install these PowerNow! plants in response to warnings from officials in the public and private sectors that the New York City metropolitan area could face power shortages in the summer of 2001.

The small power plants were rationalized as a temporary expedient, on the grounds that a long queue of larger merchant power plant projects were in line to be built. But even though some of these merchant power projects received all permits to go ahead, they fizzled after the Enron debacle. The small NYPA gas turbine generators continue to run regularly, and again the state, through NYPA, had to step up to build a new 500 MW baseload plant, saying

The highly efficient combined-cycle power-generating facility will provide New York City with adequate, reliable power supplies in the new era of electricity-industry deregulation.

The "new era of electricity-industry deregulation" ushered in by the state Public Servce Commission clearly failed if one of its goals was to assure market-driven supply of sufficient power at reasonable prices, because 44% of the supply for which the NYISO takes credit was actually due to the state, through NYPA, stepping in at the last minute to avert price and potential blackout problems. In addition, due to the failure of the NYISO market-driven approach, the previously scheduled closure of a NYPA power plant in New York City will be delayed in order to avoid reduction of supply and breach of longstanding reliability requirements.

The NYISO market failure does not stop there. The traditional utility, Con Edison, had sold nearly all its power plants, to comport with a NY PSC vision, popularized by Enron, that electricity should be sold as a deregulated commodity. Counted in the NYISO claim of new generation is a new power/steam generation plant which added 288MW to the New York City fleet of power plants -- built by Con Edison.

A merchant power company built a new 500MW plant at Astoria, (now managed by a non-utility subsidiary of a Japanese holding company), but according to a 2006 New York City Report, "the financing of this project was enabled by a 10-year power purchase agreement with Consolidated Edison Company of New York, Inc."

Thus, another 37% of the new generation supply in New York City claimed by the NYISO as being due to its markets was actually built directly by Con Edison or only with the guarantee that Con Edison - and ultimately Con Edison customers -- would buy the capacity from the plant.

In addition, due to the failure of NYISO markets to stimulate the added energy supply needed to meet growing demand for electricity, NYPA is stepping in to support, through long term contracts, the building of a new transmission line to supply 500 MW capacity from the PJM markets in New Jersey, to meet the needs of its New York City customers now that it has divested its nuclear plant at Indian Point. Retirement of the NYPA baseload Poletti power plant in Queens, has been postponed to maintain reliability due to a looming capacity reserve shortage in the New York City area. The transmission line will take advantage of market prices in PJM that are lower than NYISO prices. The cross-Hudson transmission line, which will connect a New Jersey power plant and mid-Manhattan, was fully permitted by the New York PSC in 2003, after the PSC found it is "necessary to meet near-term and anticipated long-term electric growth in the New York City market and improve electric system reliability." The line was stalled for more than three years because of market failures, until NYPA began the process of contracting to use the line so that it can be financed and constructed.

So, more than 80% of the new power plant capacity built in New York City since the advent of the NYISO was not induced by its capacity markets. Rather, when proposed market-driven projects did not materialize, the plants were built by the state (NYPA) or in reliance upon the traditional utility (Con Edison), which still has the duty to serve the public with safe and adequate service sufficient to meet demand at reasonable rates.

Growing NYISO Costs
The NYISO has grown. In 1998 the NYPP had employed approximately 111 people and had a budget of $14.5 million. Initially, the transformation of the NYPP into the NYISO was estimated to cost less than $5 million per year more than the NYPP. This rosy estimate is reflected in a Report prepared by the State of Georgia indicating at p. 121 that "New York Power Pool estimates an annual budget of $20 million." That, in hindsight, was laughably low, indicative of the wishful thinking of "Disconnected Policymakers" about markets that substituted for analysis of the economic and reliability costs of restructuring.

Similarly optimistic, a 1998 report issued by the California ISO reviewing costs and operations of other grid management agencies, as New York was changing the NYPP into the NYISO, states:

The 1998 operating budget for the [New York] power pool is $14.8 M with an additional $3-5M of operating expenses being deferred this year as part of the transition to ISO status. The total deferred expense and capital investment for the transition will be $30M by December 1998. The pool currently uses a main building and fixed assets owned by Niagara Mohawk. * * * * The total revenue requirements of the ISO when initially formed is estimated to be about $45M/yr."

Thus, at the formative stage of the NYISO, the NYPP had estimated that the added functions of the NYISO - mainly related to managing the day ahead and real time spot markets, would bring its budget from $14.5 to approximately $45 million per year -- three times what the NYPP had cost.

Tripling the NYPP budget turned out to be a gross "misunderestimation." The actual cost of the NYISO skyrocketed far beyond the initial projections. The NYISO expense of $148 million is now more than $100 million per year more than originally anticipated.

The NYISO moved into one of the largest buildings in Rensselaer County, and now employs more than 400 people, more than 300 more than the NYPP needed to coordinate the grid.
An article 1n 2005 found that six NYISO executives were among the top 25 highest paid employees of non profit agencies in the Capital District, with the following salaries:

NYISO CEO $945,810
NYISO VP, Chief Information Officer $531,593
NYISO General Counsel $452,662
NYISO VP Market Services $411,534
NYISO Chief Administrative Officer $376,492
NYISO VP Operations & Reliability $361,558
NYISO VP Government Affairs & Communications $285,013

A 2006 article again notes the highly paid NYISO staff and board of this non profit electric company:

The former head of the nonprofit organization that runs the state's electric markets was paid $656,000 last year despite working for only five months, and directors were paid as much as $130,000 while declaring they worked for only 12 hours a month, according to the group's tax returns.

Critics say the payouts are excessive, while supporters say they're necessary to attract and keep qualified executives.

The organization, known as the Independent System Operator, spent more than $148 million last year. That included more than $5 million on outside lawyers paid around $250 per hour, $2.5 million for conventions, meetings and travel, and more than $10 million for other consultants.

NYISO Costs Passed Through to Retail Consumers
The costs of the NYISO are passed on to New York electric customers as a surcharge on wholesale electric rates. That surcharge is approved by FERC with no serious review for reasonableness. New York's retail utilities then pass on the NYISO costs, as part of the energy bills consumers pay.

Accountability to the Public
In contrast to the $148 million/year NYISO cost, the entire New York Public Service Commission, which oversees more utilities than the NYISO, has a staff of approximately 532 employees and a budget of $65.9 million per year, i.e., greater responsibility, more staff, at less than half the cost of the NYISO.

Thus, "deregulation" of generating plants in New York created a new layer of privatized electric utility "market price watchers" far more expensive than the traditional state PSC rate regulation function. Consumer interests in NYISO committees are currently marginalized, outweighed by industry representatives, and the independent" NYISO board lacks even a token member accountable to the public or consumers.

The NYISO is a private utility. The NYPSC can require all electric companies in the state, including the NYISO, to operate in the public interest, so the NYISO could be held more accountable to the public.

Oversight of Rates Set by NYISO
Neither the NYISO corporate objective nor NYISO tariffs contain any duty or goal to achieve just and reasonable rates in its spot markets. FERC has the duty to assure reasonability of rates and the power to oversee NYISO costs and rates, but has assumed the market rates set by the NYISO based on sellers' demands are reasonable. As industrial customers recently pointed out, FERC has no evidence that these market rates are reasonable, and there is no effective FERC remedy when NYISO market prices are not reasonable.

Cost Effectiveness in Doubt
Adding to concerns about the ballooning NYISO costs are growing doubts about the putative benefits of this little known monopoly utility. A recent report of the American Public Power Association shows at page 13 that New York's electric rates are now second only to the state of Hawaii. Multiple Intervenors, representing New York's largest industrial customers, once proponents of market rates, have joined with other industrial groups in objecting to the effects of the NYISO and other ISO/RTO markets.

Empirical studies by academic researchers who expose their methodology and data to review -- in contrast to proprietary reports touted by restructuring proponents -- have found no discernible benefit to consumers in states like New York that restructured their electric industry to rely on effectively deregulated merchant generators selling at market rates in markets run by ISOs and RTOs.