Tuesday, April 24, 2007

DOE Designates "National Interest Electric Transmission Corridor" in New York After Critical Hearing

The Energy Policy Act of 2005
Under Section 1221 of the Energy Policy Act of 2005, the federal government was given new power to site certain transmission lines, traditionally a state function. New York, for example, has more than 11,000 miles of transmission lines constructed by investor owned utilities and the State Power Authority, under the supervision of the New York State Public Service Commission which reviews proposed transmission projects under Article VII of the New York Public Service Law.

The new federal power to issue permits for construction of transmission lines and to grant federal eminent domain power to acquire property needed for the lines is limited to situations where
  • The Department of Energy (DOE), in consultation with states, identifies "critical" transmission needs in a "congestion" study, and then designates a "National Interest Electric Transmission Corridor" within the area identified as "congested," and
  • A state has withheld approval of a proposed transmission project in such a corridor for more than one year.
Then, FERC would have power to grant a permit to build the project and to give the developer federal eminent domain power to acquire land rights for that purpose.

"Congestion" Confusion
The concept of transmission "congestion" suggests a physical or reliability issue. This notion was suggested in a recent article discussing the National Corridors which states: "congestion of existing power lines makes the electricity grid unreliable and subject to blackouts.”

Actually, the transmission system is designed to always run within reliability limits consistent with its capabilities. The major blackouts in recent decades were due to misoperation and poor maintenance of the interconnected high voltage grid components. Testimony of a leading power transmission engineer after the 2003 blackout to the New York legislature emphasized that making the alternating current grid ever larger or putting more transmission lines up does not necessarily equate with greater reliability:
Reliability and commercial use of the bulk power transmission system are two entirely different things. Reliability is a function of the reliability standards (or criteria) used, not the amount of wire in the air. A weak system with more stringent standards will be more reliable than a strong system with weak criteria – or any system where even stringent standards are not followed. Adding transmission in and of itself will not improve reliability, if the same reliability standards are used. In fact, it might actually make the system less reliable. That’s because adding transmission makes the bulk power system electrically tighter -– geo-electrically smaller. Thus a severe disturbance is likely to cause a blackout in a much larger area. It isn’t an accident that the 2003 blackout affected a larger area, and far more people, than the 1965 blackout.
Much of the drive to build more transmission lines comes from pressures to enable the physical grid to mirror economic transactions in the selling and trading of electricity. Electricity flows are governed by the laws of physics and do not follow contract paths. One cannot, say, buy electricity from a seller hundreds of miles away, and expect that when the distant power plant generates more power it will correspondingly excite the electrons at the buyer's location. Rather, many adjustments in the grid at numerous locations may be necessary.

In some instances, reliability rules limit transfer capacity to prevent an area from becoming too dependent on a single link in the system. These rules typically require that a sudden unexpected failure of the largest line or generator can be absorbed without destabilizing the alternating current grid; in the downstate New York area, the rules require the system to be run so as to be able to withstand two simultaneous outages. Thus, a desired economic transaction -- even if within the physical capacity of the existing lines -- cannot be scheduled consistent with sound operating principles.

Congestion, according to the DOE definition, is mainly an indicator of economic transactions frustrated by reliability rules:
[Congestion] occurs when actual or scheduled flows of electricity on a transmission line or a related piece of equipment are restricted below desired levels— either by the physical or electrical capacity of the line, or by operational restrictions created and enforced to protect the security and reliability of the grid.
The DOE definition includes situations where, for example, sellers and traders "desire" to "schedule" the sale of coal-fired generation to buyers at a distant location where the price is high but actual transfer capability is limited.

DOE rejected comments of the New York PSC that it should not include such "economic" congestion in its definition. As a result, the DOE map of "critical" congestion areas reflects mainly economic issues, which may shift with time depending on market developments and changes in local generation capacity.

Winners and Losers
There may often appear to be economic "winners" on one end of a transmission line and "losers" on the other. If the cost of electricity in the area of supply becomes more valuable when, due to a new line, it can be sold into a distant, more expensive market area, consumers in the supply area may see higher prices. Conversely, consumers in areas served by a new transmission line are perceived to be winners.

But the notion of "winning" lower cost electricity may prove illusory. In assuming prices will go down with new transmission, it assumes competitiveness in markets noted for their ease of manipulation and withholding strategies to maintain prices. It also assumes that high costs due to local market power concentration might be avoided by purchasing energy from other producers through more long distance transmission -- even as the power industry enters into a phase of increased consolidation through mergers that is sure to reduce the number of producers.

The 2006 DOE Congestion Study
In August 2006 DOE issued a congestion study, designating parts of Maine, New Hampshire, and wide swaths from New York to Virginia as critical congestion areas. According to affected states, DOE did not, however, fulfill the state consultation requirement of the statute before it issued the report. For example, in comments to DOE on the report the Maine Public Utilities Commission stated:
DOE never contacted or met with any Maine regulator or government representative in the process of conducting the study. * * * * In addition to violating the law by not consulting with Maine, the congestion study is an inferior product as a result of the failure. Consultation with the affected state, as required by statute, would have quickly revealed flaws in the DOE’s conclusions.
A number of states are concerned that the DOE designated critical congestion zones are environmentally sensitive areas where transmission lines are not suitable. Also, some are concerned that new federally authorized lines in the national corridors may be disruptive to orderly state and regional energy planning, because comprehensive planning must take into account solutions and priorities other than more transmission lines, such as generation located nearer to load, demand reduction, and increased use of renewable resources such as wind, water and sun.

FERC Asserts Power to Override State Denials of Transmission Lines
FERC issued new rules for issuing permits and granting federal eminent domain authority for transmission projects in DOE designated national corridors in November 2006. See our prior PULP Network article, FERC Adopts Electricity Transmission Siting Rules: Says it Can Override State Denials.

In the order adopting the rules, FERC stated its belief that it now has power to override a state denial of a transmission project in a national corridor, a decision that drew the dissent of FERC Commissioner Kelly. She said the statute gives FERC transmission siting authority only when a state has failed to act on a transmission line application within a year.

The New York Public Service Commission and others have petitioned FERC to grant a rehearing on this issue, stating:
The Commission's interpretation of Section 21 6(b)(l)(C)(i) is improper and an error of law. It allows the Commission to preempt all state authority in the siting of electric transmission facilities when Congress specifically listed the circumstances where FERC could preempt state siting authority and did not include denial of a permit within the listed circumstances.
House Oversight Committee Hearings
NASUCA filed testimony on April 25, 2007 with the House of Representatives Committee on Oversight and Government Reform, Subcommittee on Domestic Policy, identifying situations where DOE failed to consult with affected states before designating areas in which national corridor transmission lines can be built, and supporting Commissioner Kelly's position regarding the limits on FERC's power to grant permits for construction of transmission lines. Other testimony at the hearing, generally opposing the DOE process for identifying critical congestion areas, is available at the House Oversight Committee website.

DOE Designates National Corridors
DOE issued draft designations of two "National Corridors" the day after hearings criticizing the process by which areas for corridors were identified. The mid Atlantic corridor includes areas of New York in which a controversial "NYRI" transmission project has been proposed to run through many communities on an old railroad easement. These designations can be finalized after a 60 day comment period. Then, no matter what the New York Public Service Commission decides on the pending NYRI application, FERC is empowered to issue a permit and grant federal eminent domain power to the developer, under FERC's broad interpretation of its powers described above. For more information see PULP's web page on the NYRI project

Will National Corridors Increase Reliability?
While National Corridors may increase commerce over transmission lines, it is not clear that this will increase reliability. Indeed, the joint U.S. - Canada Task Force on the 2003 blackout recommended an independent study to determine the extent to which deregulatory measures that allow more energy trading had contributed to the root causes of the blackout. DOE held a conference, and received white papers on the topic, but no study was ever performed. See What Happened to the "Independent Study" of the Effects of Electric Industry Restructuring on Reliability?

Monday, April 16, 2007

Not so Smart? High Tech Metering May Harm Low Income Electricity Customers

The idea of "smart" or "advanced" metering (AMI) was given additional push by the Energy Policy Act of 2005. Congress added a new provision (Section 1252) which requires state utility regulators to consider smart metering. Congress did not mandate its universal adoption by state regulators, as utility regulation traditionally has been left to the states. Indeed, a similar requirement in Public Utility Regulatory Policies Act of 1978 (PURPA) barely passed judicial scrutiny in FERC v. Mississippi. Subsequent Tenth Amendment caselaw and changes in the composition of the Supreme Court suggest that the issue whether Congress can compel state utility regulators to consider any list of issues might be decided differently today.

"Smart" metering has been defined in a NYSERDA publication as

a concept embracing two distinct elements: meters that use new technology to capture complex energy use information and communication systems that can capture and transmit energy use information as it happens, or almost as it happens.

"Smart" metering for electricity consumers is being touted by the utility industry as a high tech method of communication between utilities and customers. In the states that "restructured" whose utilities now rely mainly on purchased power (instead of power produced by plants owned by the local utility), the new meters are seen as a way to pass through instantaneously to customers the "real time" price signals from wholesale electricity hourly spot markets, such those run by the NYISO. This assumes those prices are reasonable, and it could cause retail rates to spike severely at times when customers most need electricity.

New York City's foray into comprehensive city energy planning (in the absence of transparent comprehensive state energy planning) announced a goal to expand real time pricing, including residential customers. The Energy section of PlaNYC states:

Currently, consumers are able to make informed choices about when to use their cell phones; in peak times, they know that minutes will cost more than off-peak hours and can adjust their behavior accordingly. Although energy prices fluctuate just as much over the course of a day, this information is almost entirely unavailable to the vast majority of New Yorkers.

Apparently the authors of PlaNYC assume that elderly and ill electric customers in sweltering apartments can just shut off their cooling appliances and wait until temperatures cool and skyrocketing spot market prices come down with the same ease that those who can afford cellphones avoid using them during hours with high prices.

It is always hard to be against "smart."

Perhaps the adjective is a tip-off that all is not as it seems. There is very little evidence that large numbers of small customers will embrace real time pricing. Indeed, consumer reaction to mandatory time of use pricing for very high usage customers led the state legislature to amend the New York Public Service Law to make time of use pricing strictly voluntary for residential customers in New York State. Yet the utilities are proposing to invest billions in this effort, even those who recently spent large sums to install automated meter reading (AMR) systems. The AMR systems allow meters to be read remotely, typically from a vehicle driving by the premises.

There are ways to encourage customers to be more efficient that may be more effective than AMI meters. For example,

  • dollar meters are being tried in some areas to show customers the cost of consumption each hour, day, or other interval-- without spiking the prices.
  • inclining block rates can increase prices after a first block of usage designed to cover basic needs.
  • seasonal rates can send a predictable price signal regarding higher costs during peak months.
Instead of these lower cost options, utilities still adhere to billing systems that report usage only when it is too late for the customer to do anything about it, and still seek larger customer charges that dampen price signals and decrease energy efficiency investment payoffs, because customer charges must be paid without regard to a customer's usage.

Pricing certainty helps customers make rational choices about conservation and energy efficiency measures, and can prevent hardship to customers who lack savings to absorb unpredictably fluctuating spot market prices. Using AMI to incorporate possibly manipulated or gamed spot market prices into rates for consumers and businesses may also send the wrong price signals, and may have very harmful economic consequences.

Industrial Customer Experience with Real Time Pricing

The New York PSC has made hourly pricing (and hence more advanced metering) mandatory for large customers. This has proved controversial, because of the exposure of these large customers to NYISO spot market pricing from the utility, and the lack of better competitive opportunities.

PULP's comments to the federal task force on electricity competition pointed out that little research exists to show whether real time pricing for very large large customers actually yields desired results. PULP noted that a reference to National Grid's real time pricing program in the task force draft report may have overstated the results:

the National Grid program did not involve residential customers, . . . the participants in the RTP program were very large customers, . . . most of them were not price responsive to RTP day-ahead rates, and . . . price hedging opportunities through alternative retail electric companies were not readily available, even for these large customers.
The introduction of real time prices, however, translated into major price increases for New York's industrial customers since 2002, which rose faster in comparison to rates for other customer classes for whom energy is purchased at other than spot market prices. Other studies indicate that real time metering for just the largest customers may be sufficient to yield cost effective demand response results without the cost of deploying millions of meters for residential customers who may be less able to shift their usage to non peak hours. Nonetheless, "smart" meters are being advanced as a high tech future solution to fundamental, existing problems, such as malfunctioning and gamed wholesale markets encouraged by lax FERC regulation. See, e.g., Wellinghoff and Morenoff, Recognizing the Importance of Demand Response: the Second Half of the Wholesale Electric Market Equation. Rather than fix market manipulation that raises price by strategic bidding to create artificial scarcity now, hope is being placed in technological fixes to enable customers to reduce their usage during the moments of the highest prices demanded by wholesale sellers in the spot markets. Such optimism is not warranted. The "demand response" solution is a hypothetical market based "fix" to unreasonable rates. Theoretically it is a retreat from the legal principle that all unreasonable rates are illegal. It shifts responsibilities to buyers to avoid excessive prices in a complex but gamable spot market, and attempts to relieve sellers and regulators from their duty to demand, charge and fix only reasonable rates. The "demand response" scenarios typically involve simplistic (dare we say "dumb") assumptions that sellers will not alter their withholding and market gaming strategies or take other measures, such as not building new power plants, to maintain conditions of scarcity and opportunistic pricing.

Real Time Pricing and Other Applications of Smart Meters May Adversely Affect Many Residential Customers
There are a number of serious policy issues presented by "smart" metering technology for residential customers. A trenchant paper on "smart metering" by Barbara Alexander points out the lack of evidence to justify widespread residential real time metering, and flags important consumer issues:
The push to install more expensive smart meters (and their associated communication and data storage systems) and consider more “real time” or volatile electricity prices for residential electric customers has the potential for significant harm to many residential customers and particularly to limited income and payment troubled customers. Almost no jurisdiction has acknowledged the potential adverse impacts on these vulnerable customers who must have essential electricity service to assure household health and safety. Nor has any jurisdiction specifically ordered an analysis of proposals for dramatic changes in the pricing of electricity on limited income or payment troubled customers. * * * *
It would be unfair and poor public policy to leap into new metering technology and new methods of pricing essential electricity service to residential customers without a careful analysis and access to factual information on the impacts of such proposals on customer bills and usage patterns. The lack of such information is particularly glaring for low income customers. * * * *

Wholesale market structure and pricing mechanisms are still being vigorously debated and to rely entirely on such immature and potentially “wrong” price signals to customers who rely on essential electricity services for minimum health and safety standards should raise red flags and longer term analysis prior to embarking on expensive new metering and rate design programs.
Fortunately, the New York Public Service Law protects New York's residential customers by making real time pricing and time of use pricing strictly voluntary. There are, however, demonstration projects funded by NYSERDA now underway to implement real time metering in selected subsidized housing projects in New York City where the PSC has allowed the landlords to submeter electricity to their tenants. While submetering is generally not allowed, the PSC has approved it in situations where the landlord agrees to provide HEFPA protections and not to charge more than tariffed service from the utility. These requirements, and the general prohibition of involuntary real time metering may need to be enforced if, as is expected, real time metered customers experience higher bills and have difficulty paying them.

Higher Costs of Smart Meters
The traditional utility rate setting system rewards utilities for investing capital in their systems. For years, the largest utility capital assets typically were central power stations. In the 15 "restructured" states, utilities generally do not invest in power plants. (In New York, after "restructuring," most utilities sold their power plants, although RG&E kept its non nuclear power plants, and Con Edison "repowered" a steam/electric plant to increase output).

After the failure of holding company subsidiaries to succeed using capital previously raised for and invested in local utilities, some utilities may be looking for new ways to increase the rate base of assets upon which the utility investors are given the opportunity, thorough rates set by regulators, to earn a reasonable return. New AMI meters, deployed en masse may be a trendy way to bulk up the "rate base." For example, California utilities that no longer build power plants are now planning to spend billions on the new "smart" meters. Energy East has announced an intention to spend hundreds of millions of dollars for smart meters for residential customers in Maine and New York, including $370 million on smart metering projects in New York over the next few years.

Old meters are cheap and when regulators set rates, their depreciation costs are amortized over decades. In contrast, new meters are expensive and might be written off faster, with depreciation rates reflecting the rapid obsolescence of computerized communications equipment.This is discussed in a report of the utilities' national trade association, the Edison Electric Institute (EEI), Deciding on “Smart” Meters: The Technology Implications of Section 1252 of the Energy Policy Act Of 2005:

The issue of depreciation of new meters takes on a new meaning in the context of AMI systems. Many utilities traditionally depreciate “communications equipment” on a much shorter schedule (perhaps 7 years), than meters (perhaps 30 years). But if we install communications in the meter, which schedule should pertain? The communication and metrology functions are closely integrated in most new solid state meters. It is unlikely that, after 10 years, the meter can be retrieved from the field, the communications section removed and replaced, and the meter sent back to the field. * * * *
Decisions regarding metering strategy are very important because such a large number of meters is involved. That strategy is often shaped by the age and condition of the existing metering, and especially the depreciation status of the existing meter plant. The sudden removal and write-down of meters that may have been in use for 15 years, but were being depreciated over 30 or 50 years, can dramatically impact depreciation reserves, and income statements.

Depreciation costs are allowed as recoverable expenses in utility rate cases. So, in addition to vastly increasing the investment in metering facilities upon which a return of 10-11% a year is contemplated when rates are set, a large capital investment in meters could also increase depreciation expenses above the costs of old meters still being depreciated, requiring even higher utility revenues and rates. Also, the utilities are clamoring for federal tax breaks to write off AMI investments quickly and thus reduce actual taxes below the level of anticipated taxes used to set utility rates. So what may be very smart for utilities and purveyors of metering equipment may, for consumers, be not so smart.